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STUDY OF SELECTEDPETROLEUM REFINING RESIDUALS

INDUSTRY STUDY

August 1996

U.S. ENVIRONMENTAL PROTECTION AGENCYOffice of Solid Waste

Hazardous Waste Identification Division401 M Street, SW

Washington, DC 20460

Petroleum Refining Industry Study 107 August 1996

3.8 RESIDUAL UPGRADING

After vacuum distillation, there are still some valuable oils left in the vacuum-reducedcrude. Vacuum tower distillation bottoms and other residuum feeds can be upgraded to highervalue products such as higher grade asphalt or feed to catalytic cracking processes. Residualupgrading includes processes where asphalt components are separated from gas oil componentsby the use of a solvent. It also includes processes where the asphalt value of the residuum isupgraded (e.g., by oxidation) prior to sale. Off-spec product and fines, as well as processsludges, are study residuals from this category.

3.8.1 Process Descriptions

A total of 47 refineries reported using residual upgrading units. Four types of residualupgrading processes were reported in the 1992 RCRA §3007 Petroleum Refining Survey:

• Solvent Deasphalting• Asphalt Oxidation• Supercritical Extraction• Asphalt Emulsion

Asphalt uses are typically divided into use as road oils, cutback asphalts, asphaltemulsions, and solid asphalts. These asphalt products are used in paving roads, roofing, paints,varnishes, insulating, rust-protective compositions, battery boxes, and compounding materialsthat go into rubber products, brake linings, and fuel briquettes (REF).

3.8.1.1 Solvent Deasphalting

Residuum from vacuum distillation is separated into asphalt components and gas oilcomponents by solvent deasphalting. Figure 3.8.1 provides a simplified process flow diagram. The hydrocarbon solvent is compressed and contacted with the residuum feed. The extractcontains the paraffinic fractions (deasphalted oil or DAO), and the raffinate contains theasphaltic components. The extract and raffinate streams are sent to separate solvent recoverysystems to reclaim the solvent. The DAO may be further refined or processed, used as catalyticcracking feed, sent to lube oil processing/blending, or sold as finished product. The followingtypes of solvents are typically used for the following residual upgrading processes:

• Propane is the best choice for lube oil production due to its ability to extract onlyparaffinic hydrocarbons and to reject most of the carbon residue. (McKetta)

• A mixture of propane and butane is valuable for preparing feedstocks for catalyticcracking processes due to its ability to remove metal-bearing components. (McKetta)

• Pentane deasphalting, plus hydrodesulfurization, can produce more feed forcatalytic cracking or low sulfur fuel oil. (McKetta)


Figure 3.8.1. Solvent Deasphalting Process Flow Diagram

• One facility reported using propane and phenol solvents for deasphaltingresiduum. The DAO is sent to lube oil processing and the asphalt fraction is sentto delayed coking or fuel oil blending.

During process upsets, heavy hydrocarbons may become entrained in the solventrecovery systems, and off-specification product may be generated. The entrained hydrocarbonsare periodically removed from the unit as a process sludge and typically disposed in an industriallandfill. The off-specification product are returned to the process for re-processing.

3.8.1.2 Asphalt Oxidation (Asphalt Blowing)

Residuum from the vacuum tower or from solvent deasphalting is upgraded by oxidationwith air. Figure 3.8.2 provides a simplified process flow diagram. Air is blown through theasphalt that is heated to about 500 F, starting an exothermic reaction. The temperature iscontrolled by regulating the amount of air and by circulating oil or water through cooling coilswithin the oxidizer. The oxygen in the air reacts with hydrogen in the residuum to form water,and the reaction also couples smaller molecules of asphalt into larger molecules to create aheavier product. These reactions changes the characteristics of the asphalt to a product with thedesired properties.

During this process, coke will form on the oxidizer walls and the air sparger. The coke isremoved periodically (1 to 2 years) and sent to the coke pad for sale, mixed with asphalt for useas road material, stored, or disposed. The off-gases from the process are scrubbed to removehydrocarbons prior to burning in an thermal unit such as an incinerator or furnace.


Figure 3.8.2. Asphalt Oxidation Process Flow Diagram

Supercritical Extraction

The Residuum Oil Supercritical Extraction (ROSE) process is not, in a strict sense, asupercritical fluid extraction process. The primary extraction step is not carried out atsupercritical conditions, but at liquid conditions that take advantage of the variable solventpower of a near-critical liquid. A simplified process flow diagram is provided in Figure 3.8.3. The first stage of the ROSE process consists of mixing residuum with compressed liquid butaneor pentane and precipitating the undesired asphaltene fraction. Butane is used for its highersolvent power for heavy hydrocarbons. If an intermediate resin fraction is desired, anotherseparator and stripper system would be used directly after the asphaltene separator. To recover aresin fraction, the overhead from the asphaltene separator is heated to near the criticaltemperature of the butane. At the elevated, near-critical temperature, the solvent power of thecompressed liquid butane decreases and the resins precipitate from solution. The remainingfraction would consist of deasphalted light oils dissolved in butane. The butane is typicallyrecovered using steam.


Figure 3.8.3. Supercritical Extraction Process Flow Diagram

The DAO may be sent to FCC, blended into lubricating oil, or sold as finished product. The asphaltene and resins are reported to be blended into No. 6 fuel oil. The solvent and steamare condensed and collected in a surge drum where the solvent is recycled back to the process. This surge drum accumulates sludges during process upsets that are removed during routineprocess turnarounds and disposed as nonhazardous wastes.

Asphalt Emulsion

Residuals from the vacuum tower may be upgraded to an asphalt emulsion by millingsoap (or shear mixing) with the asphalt. These emulsions are used for road oils, where goodadhesion is required.

This process generated residuals from the cleanout of the soap tanks and from thegeneration of off-spec emulsions. The soap tank cleanout residuals are typically sent to thewastewater treatment plant, and the off-spec emulsions are sent to a pit where heat is applied tobreak the emulsion. The soap fraction is sent the wastewater treatment system and the oilfraction is recycled back to the coker feed.


Final Management# of

Streams

# of Streamsw/ Unreported

VolumeTotal Volume

(MT)Average

Volume (MT)

Other recovery onsite: reuse inextraction process

1 0 800 800

Table 3.8.1. Generation Statistics for Off-Specification Productfrom Residual Upgrading, 1992

3.8.2 Off-specification Product from Residual Upgrading

3.8.2.1 Description

This residual was identified in the consent decree based on an incorrect characterizationof data in a supporting document generated from 1983 PRDB data. After conducting a reviewof the underlying data, it was determined that volumes associated with the category of “off-specification product from residual upgrading” were actually process sludges generated duringprocess upset conditions. The Agency's finding regarding this category was corroborated duringits field investigation where this residual category was not identified and in the §3007 surveyresults. Generally, refineries re-work any residuum that does not initially meet productspecifications within the upgrading process and rarely (one reported in 1992 in the §3007survey) generate off-specification product for disposal.

3.8.2.2 Generation and Management

Off-spec product from residual upgrading includes material generated from asphaltoxidation, solvent deasphalting, and other upgrading processes. Residuals were assigned to be“off-specification product from residual upgrading” if they were assigned a residualidentification code of “off-specification product” or “fines” and were generated from a processidentified as a residual upgrading unit. These correspond to residual codes “05” and “06” inSection VII.2 of the questionnaire and process code “13” in Section IV-1.C of the questionnaire.

Based on the results of the questionnaire, 47 facilities use residual upgrading processesand thus could potentially generate off-specification product from residual upgrading. Only onefacility reported this residual, generating 800 MT that was recovered within the process. Thebase year, 1992, was expected to be a typical year for residual upgrading processes and thesurvey results are in keeping with the Agency's understanding of this process. Table 3.8.1provides a description of the quantity generated and number of reporting facilities.

3.8.2.3 Plausible Management

The Agency does not find it necessary to consider other management practices becauseoff-spec product from residual upgrading had been classified as a residual of concern based onerroneous old data and in fact is not generated for disposal.


Properties# of

Values

# ofUnreported

Values1 10th % 50th % 90th %

Flash Point, C 1 2 99.00 99.00 99.00

Specific Gravity 1 2 1.02 1.02 1.02

Aqueous Liquid, % 1 2 40.00 40.00 40.00

Organic Liquid, % 1 2 60.00 60.00 60.00

Solid, % 1 2 100.00 100.00 100.00

Other, % 1 2 100.00 100.00 100.00

Facilities were not required to do additional testing, therefore information provided was based on previously collected1

data or engineering judgment.

Table 3.8.2. Off-Specification Product from Residual Upgrading: Physical Properties

3.8.2.4 Characterization

Only one source of residual characterization data were developed during the industrystudy:

• Table 3.8.2 summarizes the physical properties of the off-specification product asreported in Section VII.A of the §3007 survey.

Because it is rarely generated, no record samples of this residual were available duringrecord sampling for analysis.

3.8.2.5 Source Reduction

No source reduction techniques were reported by industry or found in the literaturesearch for this residual.

3.8.3 Process Sludge from Residual Upgrading

3.8.3.1 Description

Process sludge is generated from miscellaneous parts of the various residual upgradingprocesses. This category is neither uniform nor routinely generated. Solvent deasphalting maygenerate a sludge due to hydrocarbon carryover in the solvent recovery system. Similarly, theROSE process may generate sludges due to process upsets in the solvent condensate collectionsystem. Additional sludges may be generated during unit turnarounds and in surge drums andcondensate knockout drums.

These percentages do not match up directly with any one of the management scenarios because the number of1

streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle Clandfill, etc.).



Streams


VolumeTotal Volume

(MT)Average

Volume (MT)

Discharge to onsite wastewatertreatment facility

3 0 3.94 1.31

Disposal in offsite Subtitle D landfill 12 0 137.56 11.46

Disposal in offsite Subtitle C landfill 1 0 0.10 0.10

Disposal in onsite Subtitle C landfill 4 0 62.00 15.50

Disposal in onsite Subtitle D landfill 2 0 7.30 3.65

Offsite incineration 1 0 9.00 9.00

Other recycling, reclamation, or reuse:onsite road material

4 0 0.22 0.06

Recovery onsite via distillation 1 0 16.00 16.00

Transfer with coke product or otherrefinery product

4 0 5.44 1.36

TOTAL 32 0 241.56 7.55

Table 3.8.3. Generation Statistics for Process Sludge from Residual Upgrading, 1992

Three residuals were reported to be managed “as hazardous”, accounting for 25 percentof the volume of this category generated in 1992.1


Twenty-one facilities reported generating a total quantity of 241 MT of this residual in1992, according to the 1992 survey. Residuals were assigned to be “process sludge fromresidual upgrading” if they were assigned a residual identification code of “process sludge” andwere generated from a process identified as a “residual upgrading” unit. These correspond toresidual code “02-D” in Section VII.2 of the questionnaire and process code “13” in Section IV-1.C of the questionnaire.

Based on the results of the questionnaire, 47 facilities use residual upgrading units andthus may generate process sludge from residual upgrading. Due to the infrequent generation ofthis residual, not all of these 47 facilities generated sludge in 1992. However, there was noreason to expect that 1992 would not be a typical year with regard to this residual's generationand management. Table 3.8.3 provides a description of the quantity generated, number ofstreams reported, number of streams not reporting volumes (data requested was unavailable andfacilities were not required to generate it), total and average volumes.



EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.8.3. The Agencygathered information suggesting that “recovery onsite in an asphalt production unit” (3.6 MT)and “transfer to offsite entity: unspecified” (unreported quantity) were used in other years. Thisnon-1992 management practice is comparable with other recovery practices reported in 1992.


Two sources of residual characterization data were developed during the industry study:

• Table 3.8.4 summarizes the physical properties of the sludge as reported inSection VII.A of the §3007 survey.

• One record sample of process sludge from residual upgrading was collected andanalyzed by EPA. This sample is summarized in Table 3.8.5.

The sample was analyzed for total and TCLP levels of volatiles, semivolatiles, metals,and ignitability. The sample was found to exhibit the toxicity characteristic for benzene. Asummary of the results is presented in Table 3.8.6. Only constituents detected in the sample areshown in this table.


Source reduction techniques were reported to be process modifications and betterhousekeeping. This residual is generated infrequently and in very small quantities, thereforelimited information was expected.


Properties# of

Values

# ofUnreported


pH 11 38 5.50 6.30 7.60

Reactive CN, ppm 8 41 0.01 0.74 50.00

Reactive S, ppm 7 42 0.01 15.00 4400.00

Flash Point, C 14 35 82.22 94.17 315.56

Oil and Grease, vol% 7 42 0.10 9.00 100.00

Total Organic Carbon, vol% 16 33 50.00 98.50 100.00


BTU Content, BTU/lb 3 46 11.00 5,000.00 10,000.00

Aqueous Liquid, % 23 26 0.00 0.00 25.00

Organic Liquid, % 23 26 0.00 5.00 90.00

Solid, % 34 15 10.00 99.00 100.00

Other, % 18 31 0.00 0.00 2.00

Particle >60 mm, % 12 37 20.00 50.00 100.00

Particle 1-60 mm, % 9 40 1.00 49.00 80.00

Particle 100 µm-1 mm, % 5 44 0.00 1.00 1.00

Particle 10-100 µm, % 1 48 0.00 0.00 0.00

Particle <10 µm, % 1 48 0.00 0.00 0.00

Median Particle Diameter, microns 1 48 60.00 60.00 60.00



Table 3.8.4. Process Sludge from Residual Upgrading: Physical Properties

Sample Number Location Description

R1-RU-01 Marathon, Indianapolis, IN ROSE unit scale/sludge

Table 3.8.5. Process Sludge from Residual Upgrading Record Sampling Locations


Table 3.8.6. Process Sludge from Residual Upgrading Characterization

Volatile Organics - Method 8260A µg/kgCAS No. R1-RU-01 Comments

Acetone 67641 B 120,000 Benzene 71432 73,000 Ethylbenzene 100414 130,000 Methylene chloride 75092 64,000 4-Methyl-2-pentanone 108101 63,000 n-Propylbenzene 103651 65,000 Toluene 108883 310,000 1,2,4-Trimethylbenzene 95636 570,000 1,3,5-Trimethylbenzene 108678 150,000 o-Xylene 95476 230,000 m,p-Xylenes 108383 / 106423 690,000 Naphthalene 91203 160,000

TCLP Volatile Organics - Methods 1311 and 8260A µg/LCAS No. R1-RU-01 Comments

Benzene 71432 2,600 Ethylbenzene 100414 570 Toluene 108883 4,100 1,2,4-Trimethylbenzene 95636 990 o-Xylene 95476 1,300 m,p-Xylene 108383 / 106423 2,800

Semivolatile Organics - Method 8270B µg/kgCAS No R1-RU-01 Comments

Acenaphthene 83329 J 38,000 Anthracene 120127 J 13,000 Dibenzofuran 132649 J 13,000 Fluorene 86737 J 39,000 Phenanthrene 85018 120,000 Pyrene 129000 J 19,000 1-Methylnaphthalene 90120 390,000 2-Methylnaphthalene 91576 570,000 Naphthalene 91203 190,000

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/LCAS No. R1-RU-01 Comments

Bis(2-ethylhexyl)phthalate 117817 J 30 2,4-Dimethylphenol 105679 J 52 Indene 95136 J 16 1-Methylnaphthalene 90120 J 96 2-Methylnaphthalene 91576 130

Table 3.8.6. Process Sludge from Residual Upgrading Characterization (continued)


TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L (continued)CAS No. R1-RU-01 Comments

2-Methylphenol 95487 J 65 3/4-Methylphenol NA J 85 Naphthalene 91203 190 Phenol 108952 J 57

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg CAS No. R1-RU-01 Comments

Aluminum 7429905 150 Antimony 7440360 14.0 Arsenic 7440382 43.0 Barium 7440393 41.0 Cadmium 7440439 1.10 Calcium 7440702 15,000 Chromium 7440473 86.0 Cobalt 7440484 13.0 Copper 7440508 92.0 Iron 7439896 200,000 Lead 7439921 20.0 Magnesium 7439954 6,500 Manganese 7439965 770 Mercury 7439976 0.11 Molybdenum 7439987 24.0 Nickel 7440020 90.0 Vanadium 7440622 100 Zinc 7440666 40.0

TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L CAS No. R1-RU-01 Comments

Calcium 7440702 130 Iron 7439896 120 Manganese 7439965 3.90 Zinc 7440666 0.24

Miscellaneous Characterization R1-RU-01 Comments

Ignitability ( oF ) 199

Notes:

B Analyte also detected in the associated method blank.J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound

that meets the identification criteria for which the result is less than the laboratory detection limit, butgreater than zero.


3.9 LUBE OIL PROCESSING

Vacuum distillates are treated and refined to produce a variety of lubricants. Wax,aromatics, and asphalts are removed by unit operations such as solvent extraction andhydroprocessing; clay may also be used. Various additives are used to meet productspecifications for thermal stability, oxidation resistances, viscosity, pour point, etc.

3.9.1 Process Descriptions

The manufacture of lubricating oil base stocks consists of five basic steps:

1) Distillation

2) Deasphalting to prepare the feedstocks

3) Solvent or hydrogen refining to improve viscosity index and quality

4) Solvent or catalytic dewaxing to remove wax and improve low temperature propertiesof paraffinic lubes

5) Clay or hydrogen finishing to improve color, stability, and quality of the lube basestock.

Based on results of the 1992 survey, 22 facilities reported conducting lube oil processing. The finished lube stocks are blended with each other and additives using batch and continuousmethods to produce formulated lubricants. The most common route to finishing lube feedstocksconsists of solvent refining, solvent dewaxing, and hydrogen finishing. The solvent and clayprocessing route or the hydrogen refining and solvent dewaxing route are also used. The all-hydrogen processing (lube hydrocracking-catalytic dewaxing-hydrorefining) route is used bytwo refiners for the manufacture of a limited number of paraffinic base oils. Figure 3.9.1provides a general process flow diagram for lube oil processing.

Lube Distillation

Lube processing may be the primary production process at some facilities, while at othersit is only one of many operations. The initial step is to separate the crude into the fractionswhich are the raw stocks for the various products to be produced. The basic process consists ofan atmospheric distillation unit and a vacuum distillation unit. The majority of the lube stocksboil in the range between 580 F and 1000 F and are distilled in the vacuum unit to the properviscosity and flash specifications. Caustic solutions are sometimes introduced to the feed toneutralize organic acids present in some crude oils. This practice reduces or eliminates corrosionin downstream processing units, and improves color, stability, and refining response of lubedistillates.


Figure 3.9.1. Lube Oil Processing Flow Diagram

Lube Deasphalting

Other facilities incorporate lube deasphalting to process vacuum residuum into lube oilbase stocks. Propane deasphalting is most commonly used to remove asphaltenes and resinswhich contribute an undesirable dark color to the lube base stocks. This process typically usesbaffle towers or rotating disk contactors to mix the propane with the feed. Solvent recovery isaccomplished with evaporators, and supercritical solvent recovery processes are also used insome deasphalting units. Another deasphalting process is the Duo-Sol Process that is used toboth deasphalt and extract lubricating oil feedstocks. Propane is used as the deasphalting solventand a mixture of phenol and cresylic acids are used as the extraction solvent. The extraction isconducted in a series of batch extractors followed by solvent recovery in multistage flashdistillation and stripping towers. See the section on Residual Upgrading for additionaldiscussion on these processes.

Lube Refining Processes

Chemical, solvent, and hydrogen refining processes have been developed and are used toremove aromatics and other undesirable constituents, and to improve the viscosity index andquality of lube base stocks. Traditional chemical processes that use sulfuric acid and clayrefining have been replaced by solvent extraction/refining and hydrotreating which are moreeffective, cost efficient, and environmentally more acceptable. Chemical refining is used mostoften for the reclamation of used lubricating oils or in combination with solvent or hydrogenrefining processes for the manufacture of specialty lubricating oils and by-products.

Chemical Refining Processes: Acid-alkali refining, also called “wet refining”, is aprocess where lubricating oils are contacted with sulfuric acid followed by neutralization with


alkali. Oil and acid are mixed and an acid sludge is allowed to coagulate. The sludge isremoved or the oil is decanted after settling, and more acid is added and the process repeated.

Acid-clay refining, also called “dry refining” is similar to acid-alkali refining with theexception that clay and a neutralizing agent are used for neutralization. This process is used foroils that form emulsions during neutralization.

Neutralization with aqueous and alcoholic caustic, soda ash lime, and other neutralizingagents is used to remove organic acids from some feedstocks. This process is conducted toreduce organic acid corrosion in downstream units or to improve the refining response and colorstability of lube feedstocks.

Hydrogen Refining Processes: Hydrogen refining, also called hydrotreating, has sincebeen replaced with solvent refining processes which are more cost effective. Hydrotreatingconsists of lube hydrocracking as an alternative to solvent extraction, and hydrorefining toprepare specialty products or to stabilize hydrocracked base stocks. Hydrocracking catalysts areproprietary to the licensors and consist of mixtures of cobalt, nickel, molybdenum, and tungstenon an alumina or silica-alumina-based carrier. Hydrorefining catalysts are proprietary butusually consist of nickel-molybdenum on alumina.

Lube hydrocracking are used to remove nitrogen, oxygen, and sulfur, and convert theundesirable polynuclear aromatics and polynuclear naphthenes to mononuclear naphthenes,aromatics, and isoparaffins which are typically desired in lube base stocks. Feedstocks consist ofunrefined distillates and deasphalted oils, solvent extracted distillates and deasphalted oils, cycleoils, hydrogen refined oils, and mixtures of these hydrocarbon fractions.

Lube hydrorefining processes are used to stabilize or improve the quality of lube basestocks from lube hydrocracking processes and for manufacture of specialty oils. Feedstocks aredependent on the nature of the crude source but generally consist of waxy or dewaxed-solvent-extracted or hydrogen-refined paraffinic oils and refined or unrefined naphthenic and paraffinicoils from some selected crudes.

Solvent Refining Processes: Feedstocks from solvent refining processes consist ofparaffinic and naphthenic distillates, deasphalted oils, hydrogen refined distillates anddeasphalted oils, cycle oils, and dewaxed oils. The products are refined oils destined for furtherprocessing or finished lube base stocks. The by-products are aromatic extracts which are used inthe manufacture of rubber, carbon black, petrochemicals, FCCU feed, fuel oil, or asphalt. Themajor solvents used today are N-methyl-2-pyrolidone (NMP) and furfural, with phenol andliquid sulfur dioxide used to a lesser extent.

The solvents are typically recovered in a series of flash towers. Steam or inert gasstrippers are used to remove traces of solvent, and a solvent purification system is used toremove water and other impurities from the recovered solvent.


Lube Dewaxing Processes

Lube feedstocks typically contain increased wax content resulting from deasphalting andrefining processes. These waxes are normally solid at ambient temperatures and must beremoved to manufacture lube oil products with the necessary low temperature properties. Catalytic dewaxing and solvent dewaxing (the most prevalent) are processes currently in use;older technologies include cold settling, pressure filtration, and centrifuge dewaxing.

Catalytic Dewaxing: Because solvent dewaxing is relatively expensive for theproduction of low pour point oils, various catalytic dewaxing (selective hydrocracking)processes have been developed for the manufacture of lube oil base stocks. The basic processconsists of a reactor containing a proprietary dewaxing catalyst followed by a second reactorcontaining a hydrogen finishing catalyst to saturate olefins created by the dewaxing reaction andto improve stability, color and demulsibility of the finished lube oil.

Solvent Dewaxing: Solvent dewaxing consists of the following steps: crystallization,filtration, and solvent recovery. In the crystallization step, the feedstock is diluted with thesolvent and chilled, solidifying the wax components. The filtration step removes the wax fromthe solution of dewaxed oil and solvent. Solvent recovery removes the solvent from the waxcake and filtrate for recycle by flash distillation and stripping. The major processes in use todayare the ketone dewaxing processes. Other processes that are used to a lesser degree include theDi/Me Process and the propane dewaxing process.

The most widely used ketone processes are the Texaco Solvent Dewaxing Process andthe Exxon Dilchill Process. Both processes consist of diluting the waxy feedstock with solventwhile chilling at a controlled rate to produce a slurry. The slurry is filtered using rotary vacuumfilters and the wax cake is washed with cold solvent. The filtrate is used to prechill thefeedstock and solvent mixture. The primary wax cake is diluted with additional solvent andfiltered again to reduce the oil content in the wax. The solvent recovered from the dewaxed oiland wax cake by flash vaporization and recycled back into the process. The Texaco SolventDewaxing Process (also called the MEK process) uses a mixture of MEK and toluene as thedewaxing solvent, and sometimes uses mixtures of other ketones and aromatic solvents. TheExxon Dilchill Dewaxing Process uses a direct cold solvent dilution-chilling process in a specialcrystallizer in place of the scraped surface exchangers used in the Texaco process.

The Di/Me Dewaxing Process uses a mixture of dichloroethane and methylene dichlorideas the dewaxing solvent. This process is used by a few refineries in Europe. The PropaneDewaxing Process is essentially the same as the ketone process except for the following: propane is used as the dewaxing solvent and higher pressure equipment is required, and chillingis done in evaporative chillers by vaporizing a portion of the dewaxing solvent. Although thisprocess generates a better product and does not require crystallizers, the temperature differentialbetween the dewaxed oil and the filtration temperature is higher than for the ketone processes(higher energy costs), and dewaxing aids are required to get good filtration rates.


Lube Oil Finishing Processes

Today, hydrogen finishing processes (also referred to as hydrorefining) have largelyreplaced the more costly acid and clay finishing processes. Hydrogen finishing processes aremild hydrogenation processes used to improve the color, odor, thermal, and oxidative stability,and demulsibility of lube base stocks. The process consists of fixed bed catalytic reactors thattypically use a nickel-molybdenum catalyst to neutralize, desulfurize, and denitrify lube basestocks. These processes do not saturate aromatics or break carbon-carbon bonds as in otherhydrogen finishing processes. Sulfuric acid treating is still used by some refiners for themanufacture of specialty oils and the reclamation of used oils. This process is typicallyconducted in batch or continuous processes similar to the chemical refining processes discussedearlier, with the exception that the amount of acid used is much lower that used in acid refining. Clay contacting involves mixing the oil with fine bleaching clay at elevated temperaturefollowed by separation of the oil and clay. This process improves color and chemical, thermal,and color stability of the lube base stock, and is often combined with acid finishing. Claypercolation is a static bed absorption process used to purify, decolorize, and finish lube stocksand waxes. It is still used in the manufacture of refrigeration oils, transformer oils, turbine oils,white oils, and waxes.

3.9.2 Treating Clay from Lube Oil Processing

3.9.2.1 Description

The majority of treating clays (including other sorbents) generated from lube oilprocessing are from acid-clay treating in refining or lube oil finishing. The average volume isapproximately 40 metric tons.


The spent clay is vacuumed or gravity dumped from the vessels into piles or intocontainers such as drums and roll-off bins. Only one residual was reported to be managed “ashazardous” from this category in 1992.

Seven facilities reported generating a total quantify of approximately 733 metric tons ofthis residual in 1992, according to the 1992 RCRA §3007 Questionnaire. Residual wereassigned to be “treating clay from lube oil processes” if they were assigned a residualidentification code of “spent sorbent” and were generated from a lube oil process. Thesecorrespond to residual code “05” in Section VII.A of the questionnaire and process code “17” inSection IV.C of the questionnaire. Table 3.9.1 provides a description of the 1992 managementpractices, quantity generated, number of streams reported, number of streams not reportingvolumes (data requested was unavailable and facilities were not required to generate it), total andaverage volumes.

EPA did not compare these management practices to those reported for the broader category of “treating clay from2

clay filtering” due to the diverse types of materials included in this miscellaneous category.



Streams


VolumeTotal Volume

(MT)Average

Volume (MT)

Disposal in offsite Subtitle D landfill 1 1 36.7 36.7

Disposal in offsite Subtitle C landfill 2 0 78.7 39.4

Disposal in onsite Subtitle C landfill 1 0 5 5

Onsite land treatment 1 0 9.8 9.8

Other recycling, reclamation, or reuse: cement plant

1 0 249.2 249.2

Other recycling, reclamation, or reuse: onsite regeneration

12 0 354 29.5

TOTAL 18 1 733.4 40.7

Table 3.9.1. Generation Statistics for Treating Clay from Lube Oil, 1992


EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.9.1. No data wereavailable to the Agency suggesting any other management practices. In addition, EPA comparedthe management practice reported for lube oil treating clay to those reported for treating claysfrom extraction, alkylation, and isomerization based on expected similarities. No additional2

management practices were reported.


Two sources of residual characterization were developed during the industry study:

• Table 3.9.2 summarizes the physical and chemical properties of treating clay from lubeoil processes as reported in Section VII.A of the §3007 survey.

• One record sample of treating clay from lube oil processes was collected and analyzedby EPA. Sampling information is summarized in Table 3.9.3.

The collected sample is expected to be generally representative of treating clay from lubeoil processes. The sample was analyzed for total and TCLP levels of volatiles, semi-volatiles,and metals. The sample did not exhibit any of the hazardous waste characteristics. A summaryof the analytical results is presented in Table 3.9.4. Only constituents detected in the sample arereported.


Properties# of

Values

# ofUnreported

Values 10th % 50th % 90th %

pH 3 17 3.80 7.40 7.40

Flash Point, C 2 18 95.00 95.00 95.00




Aqueous Liquid, % 4 16 0.00 0.00 0.00

Organic Liquid, % 4 16 0.00 0.00 0.00

Solid, % 7 13 100.00 100.00 100.00

Particle >60 mm, % 2 18 0.00 0.00 0.00

Particle 1-60 mm, % 2 18 0.00 45.80 91.60

Particle 100 µm-1 mm, % 2 18 8.40 54.20 100.00

Particle 10-100 µm, % 4 16 0.00 50.00 100.00

Particle <10 µm, % 2 18 0.00 0.00 0.00




Table 3.9.2. Treating Clay from Lube Oil: Physical Properties

Sample Number Location Description

R13-CL-01 Shell, Deer Park, TX Pellets from wax treating

Table 3.9.3. Treating Clay from Lube Oil Processing Record Sampling Locations


This residual is generated infrequently and in very small quantities. Treating clays usefor product polishing in lube oil manufacturing are being phased out by industry. No sourcereduction methods were reported by industry or found in the literature search.


Table 3.9.4. Treating Clay from Lube Oil Processing Characterization

Volatile Organics - Method 8260A µg/kg

CAS No. R13-CL-01 Comments

Benzene 71432 11

Ethylbenzene 100414 J 8

Methylene chloride 75092 24

n-Propylbenzene 103651 J 8

Toluene 108883 31

1,2,4-Trimethylbenzene 95636 78

1,3,5-Trimethylbenzene 108678 34

o-Xylene 95476 18

m,p-Xylenes 108383 / 106423 52

TCLP Volatile Organics - Methods 1311 and 8260A µg/L


Methylene chloride 75092 B 2,600

Semivolatile Organics - Method 8270B µg/kg

CAS No R13-CL-01 Comments

Bis(2-ethylhexyl)phthalate 117817 38,000

Di-n-butyl phthalate 84742 J 390

N-Nitrosodiphenylamine 86306 J 470

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L


2-Methylphenol 95487 J 18

3/4-Methylphenol NA J 18

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg


Aluminum 7429905 140,000

Barium 7440393 53.0

Calcium 7440702 1,300

Chromium 7440473 100

Copper 7440508 260

Iron 7439896 19,000

Lead 7439921 36.0

Manganese 7439965 180

Vanadium 7440622 130

Zinc 7440666 120

Table 3.9.4. Treating Clay from Lube Oil Processing Characterization (continued)


TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L


Aluminum 7429905 12.0

Copper 7440508 0.90

Manganese 7439965 1.50

Zinc 7440666 B 0.94

Miscellaneous Characterization

R13-CL-01 Comments

Ignitability ( oF ) NA

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound

that meets the identification criteria for which the result is less than the laboratory detection limit, butgreater than zero.

ND Not Detected.NA Not Applicable.


TechniqueNumber ofFacilities

Percentage ofFacilities1

Amine-based sulfur removal 106 86

Claus sulfur recovery2 101 82

Other sulfur removal or recovery 16 13

SCOT®-type tail gas unit3 50 41

Other tail gas treating unit4 19 15

Percentage of the 123 facilities reporting any sulfur removal/complex technique.1

Note that more facilities perform sulfur removal than perform sulfur recovery. Some refineries transfer their H S-22

containing amine offsite to another nearby refinery.

Shell and other companies license similar technologies. All are included here as “SCOT®-type.”3

14 facilities use the Beavon-Stretford process for tail gas treating.4

Table 3.10.1. Sulfur Removal Technologies Reported in RCRA §3007 Questionnaire

3.10 H S REMOVAL AND SULFUR COMPLEX2

3.10.1 Process Description

All crude oil contains sulfur, which must be removed at various points of the refiningprocess. The predominant technique for treating light petroleum gases is (1) amine scrubbingfollowed by (2) recovery of elemental sulfur in a Claus unit followed by (3) final sulfur removalin a tail gas unit. This dominance is shown in Table 3.10.1, which presents the sulfurcomplex/removal processes reported in the RCRA §3007 Survey.

Caustic or water is often used in conjunction with, or instead of, amine solution toremove sulfur, particularly for liquid petroleum fractions. These processes, however, aregenerally not considered sulfur removal processes because either (1) the sulfur is not furthercomplexed from these solutions (i.e., is not removed from the solution), or (2) if removed, itoccurs in a sour water stripper which is in the domain of the facility's wastewater treatmentsystem. Such processes are considered to be liquid treating with caustic, which was discussed inthe Listing Background Document.

The dominant sulfur removal/complex train, amine scrubbing followed by Claus unitfollowed by SCOT®-type tail gas treating, is discussed below. In addition, the second-mostpopular tail gas system, the Beavon-Stretford system, is discussed. Finally, other processesreported in the questionnaires are discussed.


Figure 3.10.1. Amine Sulfur Removal Process Flow Diagram

3.10.1.1 Amine Scrubbing

As shown in Table 3.10.1, amine scrubbing is used by most facilities, with 106 refineriesreporting this process in the questionnaire. A typical process flow diagram for an aminescrubbing system is shown in Figure 3.10.1. The purpose of the unit is to remove H S from2

refinery fuel gas for economical downstream recovery. Fuel gas from the refinery is fed to acountercurrent absorber with a 25 to 30 percent aqueous solution of amine such asmonoethanolamine (MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA). TheH S reacts with the amine solution to form a complex, “rich” amine. Typically, a refinery will2

have several absorbers located throughout the refinery depending on the location of service. These “rich” streams are combined and sent to a common location at the sulfur plant where theH S is stripped from the amine in the reverse reaction. The “lean” amine is recycled back to the2

absorbers.

3.10.1.2 Claus Unit

The H S from the sulfur removal unit is most often recovered in a Claus system as2

elemental sulfur. Table 3.10.1 shows that 101 refineries reported this process in thequestionnaire. A typical process flow diagram for a Claus unit is shown in Figure 3.10.2. In aClaus unit, the H S is partially combusted with air to form a mixture of SO and H S. It then2 2 2

passes through a reactor containing activated alumina catalyst to form sulfur by the followingendothermic reaction:

2 H S + SO --> 3 S + 2 H O2 2 2

The reaction is typically conducted at atmospheric pressure. The resulting sulfur is condensed toits molten state, drained to a storage pit, and reheated. The typical Claus unit consists of threesuch reactor/condenser/reheaters to achieve an overall sulfur removal yield of 90 to 95 percent.


Figure 3.10.2. Claus Sulfur Recovery Process Flow Diagram

At this point the tail gas can be (1) combusted and released to the atmosphere, or (2) sent to atail gas unit to achieve greater sulfur reduction.

3.10.1.3 SCOT Tailgas Unit®

The most common type of tail gas unit uses a hydrotreating reactor followed by aminescrubbing to recover and recycle sulfur, in the form of H S, to the Claus unit. Shell licenses this2

technology as the Shell Claus Offgas Treating (SCOT ) unit; many other refineries reported®

using similar designs licensed by other vendors. All can be represented by the generalizedprocess flow diagram shown in Figure 3.10.3.

Tail gas (containing H S and SO ) is contacted with H and reduced in a hydrotreating2 2 2

reactor to form H S and H O. The catalyst is typically cobalt/molybdenum on alumina. The gas2 2

is then cooled in a water contractor. The water circulates in the column and requires periodicpurging due to impurity buildup; filters may be used to control levels of particulates orimpurities in the circulating water.

The H S-containing gas enters an amine absorber which is typically in a system2

segregated from the other refinery amine systems discussed above. The purpose of segregationis two-fold: (1) the tail gas treater frequently uses a different amine than the rest of the plant,such as MDEA or diisopropyl amine (DIPA), and (2) the tail gas is frequently cleaner than therefinery fuel gas (in regard to contaminants) and segregation of the systems reduces maintenancerequirements for the SCOT unit. Amines chosen for use in the tail gas system tend to be more®

selective for H S and are not affected by the high levels of CO in the offgas.2 2


Figure 3.10.3. SCOT Tail Gas Sulfur Removal Process Flow Diagram®

The “rich” amine generated from this step is desorbed in a stripper; the lean amine isrecirculated while the liberated H S is sent to the Claus unit. Particulate filters are sometimes2

used to remove contaminants from lean amine.

3.10.1.4 Beavon-Stretford Tail Gas Unit

This system was reported to be used by 14 facilities. A hydrotreating reactor convertsSO in the offgas to H S. The generated H S is contacted with Stretford solution (a mixture of2 2 2

vanadium salt, anthraquinone disulfonic acid (ADA), sodium carbonate, and sodium hydroxide)in a liquid-gas absorber. The H S reacts stepwise with sodium carbonate and ADA to produce2

elemental sulfur, with vanadium serving as a catalyst. The solution proceeds to a tank whereoxygen is added to regenerate the reactants. One or more froth or slurry tanks are used to skimthe product sulfur from the solution, which is recirculated to the absorber.

3.10.1.5 Other Processes

Although the amine/Claus train followed by a SCOT or Beavon-Stretford tail gas unit is®

the dominant system used in the industry, it is not exclusive. Some refineries, mostly smallasphalt plants, do not require sulfur removal processes at all, while others use alternativetechnologies. Each of these processes are used by less than five refineries, and most often areused by only one or two facilities. In decreasing order of usage, these other processes are asfollows:


Sulfur Removal/Recovery Processes

Sodium Hydrosulfide: Fuel gas containing H S is contacted with sodium hydroxide in2

an absorption column. The resulting liquid is product sodium hydrosulfide (NaHS).

Iron Chelate: Fuel gas containing H S is contacted with iron chelate catalyst dissolved2

in solution. H S is converted to elemental sulfur, which is recovered.2

Stretford: Similar to iron chelate, except Stretford solution is used instead of ironchelate solution.

Ammonium Thiosulfate: In this process, H S is contacted with air to form SO . The2 2

SO is contacted with ammonia in a series of absorption column to produce ammonium2

thiosulfate for offsite sale. (Kirk-Othmer, 1983)

Hyperion: Fuel gas is contacted over a solid catalyst to form elemental sulfur. Thesulfur is collected and sold. The catalyst is comprised of iron and naphthoquinonsulfonic acid.

Sulfatreat: The Sulfatreat material is a black granular solid powder; the H S forms a2

chemical bond with the solid. When the bed reaches capacity, the Sulfatreat solids are removedand replaced with fresh material. The sulfur is not recovered.

A few facilities report sour water stripping, which was not part of the scope of thesurvey. The actual number of sour water strippers is likely to be much greater than reported inthe questionnaire.

Hysulf: This process is under development by Marathon Oil Company and was notreported by any facilities in the questionnaire. Hydrogen sulfide is contacted with a liquidquinone in an organic solvent such as n-methyl-2-pyrolidone (NMP), forming sulfur. The sulfuris removed and the quinone reacted to its original state, producing hydrogen gas (The NationalEnvironmental Journal, March/April 1995).

Tail Gas Processes

Caustic Scrubbing: An incinerator converts trace sulfur compounds in the offgas toSO . The gas is contacted with caustic which is sent to the wastewater treatment system.2

Polyethylene Glycol: Offgas from the Claus unit is contacted with this solution togenerate an elemental sulfur product. Unlike the Beavon Stretford process, no hydrogenationreactor is used to convert SO to H S. (Kirk-Othmer, 1983)2 2

Selectox: A hydrogenation reactor converts SO in the offgas to H S. A solid catalyst in2 2

a fixed bed reactor converts the H S to elemental sulfur. The elemental sulfur is recovered and2

sold. (Hydrocarbon Processing, April 1994).

Sulfite/Bisulfite Tail Gas Treating Unit: Following Claus reactors, an incineratorconverts trace sulfur compounds to SO . The gas is contacted with sulfite solution in an2


absorber, where SO reacts with the sulfite to produce a bisulfite solution. The gas is then2

emitted to the stack. The bisulfite is regenerated and liberated SO is sent to the Claus units for2

recovery. (Kirk-Othmer, 1983)

3.10.2 Off-Specification Product from Sulfur Complex and H S Removal Facilities2

3.10.2.1 Description

Elemental sulfur is the most common product from sulfur complex and H S removal2

facilities, although a small number of facilities generate product sodium hydrosulfide orammonium thiosulfate, as discussed in Section 3.10.1.5. Like other refinery products, sulfurmust meet certain customer specifications such as color and impurity levels. The failure of therefinery to meet these requirements causes the sulfur to be “off-spec.”

Stretford System

Although the Beavon-Stretford system is used by only 14 refineries, off-spec sulfurgenerated from this process accounts for 2/3 of the refinery-wide 1992 generation of off-specsulfur. Sources of this volume are as follows:

• Product sulfur: Some refineries routinely dispose of their continuously generatedproduct sulfur rather than sell it. Presumably, these refineries have operationaldifficulties making “on-spec” sulfur from the vanadium-catalyzed process. The smallnumber of refineries managing sulfur this way account for most of the quantity of off-spec sulfur generated industry-wide. Other refineries sell all or most of their productsulfur and only dispose of sulfur generated from spills, etc.

• Filtered solids from spent Stretford solution: As discussed further in Section3.10.3, many refineries report that a portion of the circulating Stretford solution mustbe purged to remove impurities in the system. After purging, some refineries filter outthe solids prior to further managing the spent solution.

• Turnaround sludge (sediment): Every few years, the process units are thoroughlycleaned as preparation for maintenance. The principal source of this turnaroundsludge is the froth (slurry) tank.

• Miscellaneous sludges (sediments): Other solids build up in the system, includingtank sludges and process drain pit sludge. They are removed intermittently.

Every residual generated by the Stretford process contains elemental (product) sulfurbecause sulfur is a reaction product. Most refineries designated the above materials as off-specproduct in their questionnaire response, and these residuals are included in statistics discussedlater in this Section.


streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer to offsiteentity, etc.).


Claus System

Based on database responses, many Claus units generate off-spec sulfur at frequenciesranging from 2 months to 2 years. Sources of such sulfur are spills, process upsets, turnarounds,or maintenance operations. Some refineries generate off-spec sulfur more frequently; onerefinery reports that certain spots are drained daily to ensure proper operation.

Other Systems

The amine scrubbing and SCOT units do not generate off-spec sulfur because they do®

not generate product sulfur (their product is H S, an intermediate for the Claus sulfur recovery2

unit). Other systems generating elemental sulfur or product sulfur compounds can generate off-spec sulfur for the same reasons described above for Claus and Stretford processes.


Most off-spec sulfur from Claus units is solid with little water content. The off-specsulfur residuals described above from the Stretford process contain varying levels of solutionwhich would give the residual a solid, sludge, or slurry form. Some refineries report filteringthis material to generate off-spec sulfur with higher solids levels.

Based on the questionnaire responses, most refineries (regardless of process) reportedstoring off-spec sulfur onsite in a drum, in a dumpster, or in a pile prior to its final destination. In 1992, five facilities reported classifying this residual as RCRA hazardous (a total quantity of2,551 MT were reported), however, the hazard waste code was generally not reported.3

Sixty facilities reported generating a total quantity of almost 9,650 MT of this residual in1992, according to the 1992 RCRA §3007 Survey. As stated in Section 3.10.1, 123 facilitiesreported sulfur complex/removal processes. The remaining 63 facilities either report nevergenerating this residual, or reported generation in years other than 1992 (due to intermittentgeneration). There was no reason to expect that 1992 would not be a typical year with regard tothis residual's generation and management. Because most of the generation quantity isconcentrated at a small number of facilities using the Stretford process, however, futureoperational changes at those sites could greatly impact the industry-wide residual generationrate.

Residuals were assigned to be “off-spec sulfur” if they were assigned a residualidentification code of “off-spec product” and were generated from a process identified as a sulfurremoval or complex unit. These correspond to residual code 05 in Section VII.A of thequestionnaire and process code 15 in Section IV.C of the questionnaire. Table 3.10.2 provides adescription of the 1992 management practices, quantity generated, number of streams reported,number of streams not reporting volumes (data requested was unavailable and facilities were notrequired to generate it), total and average volumes.



Streams


VolumeTotal Volume

(MT)Average

Volume (MT)

Disposal in offsite Subtitle D landfill 41 10 5,043.53 123.01

Disposal in offsite Subtitle C landfill 6 2 3,575.50 510.79



Other disposal offsite (anticipated to beSubtitle C landfill)

1 0 0.10 0.10

Offsite incineration 1 0 0.70 0.70

Offsite land treatment 1 0 0.95 0.95

Other recovery onsite: sulfur plant 1 1 2.00 2.00

Transfer for use as an ingredient inproducts placed on the land

1 0 15.00 15.00

Transfer to other offsite entity 1 2 487.80 487.80


4 0 6.52 1.63

TOTAL 70 21 9,646.57 137.8

Table 3.10.2. Generation Statistics for Off-Spec Sulfur, 1992


EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.2. No data wereavailable to the Agency suggesting any other management practices.



• Table 3.10.3 summarizes the physical and chemical properties of off-spec sulfur asreported in Section VII.A of the §3007 survey.

• Four record samples of off-spec sulfur were collected and analyzed by EPA. All ofthese were collected from the Claus process. Sampling information is summarized inTable 3.10.4.

The collected samples are expected to be representative of off-spec sulfur generated fromClaus units, the sulfur recovery process used by most refineries. They are not expected torepresent off-spec sulfur from the Stretford process because vanadium would be present in off-spec sulfur from this process at levels higher than those found in off-spec sulfur from Clausunits. Concentrations of other contaminants may also differ.


All four record samples were analyzed for total and TCLP levels of volatiles,semivolatiles and metals. None of the samples were found to exhibit a hazardous wastecharacteristic. A summary of the analytical results is presented in Table 3.10.5. Onlyconstituents detected in at least one sample are shown in this table.


During EPA's site visit, one facility was observed to generate “off-spec” sulfur productdaily. Portions of the sulfur plant are being replaced with a newer design. As a result, wastesulfur residual from equipment “low points” will no longer be generated.


Properties# of

Values

# ofUnreported


pH 45 62 2.80 5.50 9.00

Reactive CN, ppm 20 87 0.00 0.25 20.85

Reactive S, ppm 35 72 0.00 1.23 92.00

Flash Point, C 30 77 60.00 93.33 187.78



Vapor Pressure, mm Hg 9 98 0.00 0.10 11.00

Vapor Pressure Temperature, C 9 98 20.00 140.00 284.00


Specific Gravity Temperature, C 11 96 4.00 15.60 21.10

BTU Content, BTU/lb 15 92 0.00 4,606.00 4,606.00

Aqueous Liquid, % 46 61 0.00 0.00 5.00

Organic Liquid, % 44 63 0.00 0.00 100.00

Solid, % 82 25 60.00 100.00 100.00

Particle >60 mm, % 28 79 0.00 80.00 100.00

Particle 1-60 mm, % 24 83 0.00 22.50 100.00

Particle 100 µm-1 mm, % 23 84 0.00 0.00 100.00

Particle 10-100 µm, % 14 93 0.00 0.00 0.00

Particle <10 µm, % 14 93 0.00 0.00 0.00




Table 3.10.3. Off-Specification Sulfur: Physical Properties

Sample number Facility Description

R1-SP-01 Marathon, Indianapolis, IN Claus unit: contents of product tank destined fordisposal

R2-SP-01 Shell, Wood River, IL Claus unit: generated daily from unit “low spots”

R7B-SP-01 BP, Belle Chase, LA Claus unit: from cleaning and turnaround ofproduct tank

R23-SP-01 Chevron, Salt Lake City,UT

Claus unit: from loading spills, connectionleaks, and sumps

Table 3.10.4. Off-Specification Sulfur Record Sampling Locations

Petroleum

Refining Industry S

tudy137

August 1996

Table 3.10.5. Residual Characterization Data for Off-Specification Sulfur


CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments

Acetone 67641 < 25 < 25 < 5 2,000 514 2,000



Acetone 67641 B 2,300 < 50 < 50 B 160 640 2,300



Bis(2-ethylhexyl) phthalate 117817 J 75 < 165 880 460 395 880

Benzo(a)pyrene 50328 < 165 < 165 < 165 J 110 110 110 1

Benzo(g,h,i) perylene 191242 < 165 < 165 < 165 J 130 130 130 1

Chrysene 218019 < 165 < 165 < 165 J 270 191 270

Di-n-butyl phthalate 84742 < 165 < 165 J 140 < 165 140 140 1

Di-n-octyl phthalate 117840 < 165 < 165 J 180 < 165 169 180

Pyridine 110861 < 165 J 160 < 165 < 165 160 160 1

Fluorene 86737 < 165 < 165 J 280 < 165 194 280

2-Methylchrysene 3351324 < 330 < 330 < 330 J 230 230 230 1

1-Methylnaphthalene 90120 < 330 < 330 680 < 330 418 680

2-Methylnaphthalene 91576 < 165 < 165 760 < 165 314 760

Phenanthrene 85018 < 165 < 165 J 140 < 165 140 140 1



Bis(2-ethylhexyl) phthalate 117817 < 50 J 11 < 50 < 50 11 11 1

Petroleum

Refining Industry S

tudy138

August 1996

Table 3.10.5. Residual Characterization Data for Off-Specification Sulfur (continued)



Aluminum 7429905 < 20 < 20 780 350 293 780

Barium 7440393 < 20 < 20 90.0 < 20 37.5 90.0

Calcium 7440702 < 500 < 500 3,400 < 500 1,225 3,400

Chromium 7440473 2.70 < 1.00 62.0 4.70 17.6 62.0

Copper 7440508 < 2.50 < 2.50 68.0 8.40 20.4 68.0

Iron 7439896 62.0 610 22,000 710 5,846 22,000

Lead 7439921 < 0.30 0.83 4.30 3.40 2.21 4.30

Manganese 7439965 < 1.50 < 1.50 91.0 3.20 24.3 91.0

Molybdenum 7439987 < 6.50 < 6.50 15.0 < 6.50 8.63 15.0

Nickel 7440020 < 4.00 < 4.00 21.0 < 4.00 8.25 21.0

Zinc 7440666 < 2.00 < 2.00 140 34.0 44.5 140



Aluminum 7429905 < 1.00 < 1.00 5.90 < 1.00 2.23 5.90

Calcium 7440702 < 25.0 < 25.0 62.0 < 25.0 34.3 62.0

Chromium 7440473 < 0.05 < 0.05 0.43 < 0.05 0.15 0.43

Iron 7439896 < 0.50 16.0 44.0 1.50 15.5 44.0

Manganese 7439965 < 0.08 0.26 0.77 < 0.08 0.30 0.77

Zinc 7440666 0.31 < 0.10 B 2.90 B 0.87 1.05 2.90

Comments:


Notes:

B Analyte also detected in the associated method blank.J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than

zero.


streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle Clandfill, transfer for reclamation, etc.).


3.10.3 Off-Specification Treating Solution from Sulfur Complex and H S Removal2

Facilities


All treating solutions used in refinery sulfur removal systems are regenerative, meaningthe solution is used over and over in a closed system (for example, amines use multipleabsorption/desorption cycles, while Stretford solution undergoes multiple reversible reactions). In the following instances the treating solution becomes “off-spec” and cannot be reused:

• Amine systems. At most refineries, amine continuously leaves the closed systemthrough entrainment in overhead gas, leaks, and other routes. The amine is collectedin various locations such as sumps and either returned to the process or discharged tothe refinery's wastewater treatment (possibly due to purity constraints).

At some refineries, the circulating amine must be replaced in whole or in part due tocontamination or process upset. Rarely, a refinery may change from one amine toanother and completely remove the existing amine from the system prior tointroducing the new solution.

• Stretford systems. Many refineries report that a portion of the circulating Stretfordsolution must be purged to remove impurities in the system. After purging, somerefineries filter out the solids prior to further managing the spent solution. Stretfordsystems are used at a smaller number (15) of facilities. Unlike amine systems,Stretford solution is generally used only in tail gas treating.

During operation, the treating solution alternatively becomes “rich” (i.e., containing H S) and2

“lean” (i.e., containing low levels or no H S). In all observed cases, a refinery will generate off-2

spec treating solution when it is “lean.”

Approximately 800 MT of off-spec treating solution generated in 1992 was identified by6 facilities as displaying hazardous characteristics. The facilities designated the wastes with4

hazardous waste codes D002 (corrosive), D003 (reactive), D010 (TC selenium), and D018 (TCbenzene). No single hazardous waste code was reported by more than one facility.


Spent Amine Solution

As discussed in Section 3.10.1, the amine sulfur removal process is the dominant sulfurremoval process for gas streams used in the industry. Amine solutions are aqueous and aretypically stored in covered sumps, tanks, etc. In the 1992 questionnaire, most facilities did not



Streams


VolumeTotal Volume

(MT)Average

Volume (MT)

Discharge to onsite wastewater treatmentfacility

40 16 1,224.2 30.6

Discharge to offsite privately-owned WWTfacility

1 0 152 152

Disposal in onsite or offsite undergroundinjection

4 0 673.3 168.3

Disposal in offsite Subtitle D landfill 1 0 200 200

Disposal in offsite Subtitle C landfill 1 0 39 39

Disposal in onsite surface impoundment 3 0 0.8 0.3

Neutralization 1 0 0.2 0.2

Onsite boiler 1 0 9.1 9.1

Other recovery onsite: recycle to theprocess

3 4 12.8 4.27

Recovery onsite in catalytic cracker 1 0 1,150 1,150

Transfer to other offsite entity/aminereclaimer

3 0 166 55.3

TOTAL 59 20 4,627.4 78.4

Table 3.10.6. Generation Statistics for Spent Amine for H S Removal, 19922

report how their off-spec treating solution is stored prior to final management; those that didindicated storage in a tank (most common), storage in a container, or storage in a sump.

Forty-four facilities reported generating a total quantity of 4,627 MT of spent amine in1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned to be “off-spec treating solution (spent amine)” if they were assigned a residual identification code of“treating solution” and were generated from a sulfur complex or H S removal process. These2

correspond to residual codes of “04-B” or “04-C” in Section VII.A and process code “15-A” and“15-D” in Section IV-1.C of the questionnaire. Based on the results of the questionnaire,approximately 123 facilities employ some type of sulfur removal system (most of these systemsemploy treating solution). Many facilities generate this residual on an intermittent basis, or onlyduring unusual circumstances such as upsets. Therefore, not all of these 123 facilities areexpected to generate off-spec treating solution.

Table 3.10.6 provides a description of the 1992 management practices, quantitygenerated, number of streams reported, number of streams not reporting volumes (data requestedwas unavailable and facilities were not required to generate it), total and average volumes.



Streams


VolumeTotal

Volume (MT)Average

Volume (MT)

Discharge to onsite wastewater treatmentfacility

4 2 4,830 1,207.5

Discharge to offsite privately-ownedWWT facility

3 0 6,111.5 2,037.2

Disposal in onsite Subtitle D landfill 1 0 711 711

Transfer metal catalyst for reclamation orregeneration

2 0 5,127 2563.5

Transfer of acid or caustic forreclamation, regeneration, or recovery

3 0 2,475 825

TOTAL 13 2 19,254.5 1,481

Table 3.10.7. Generation Statistics for Stretford Solution for H S Removal, 19922

Spent Stretford Solution

The second most frequently used process is the Stretford sulfur removal/complexprocess. Stretford solutions are aqueous and are typically stored in covered sumps, tanks, etc.

Twelve facilities reported generating a total quantity of 19,254.5 MT of spent Stretfordsolution in 1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned tobe “spent Stretford solution” if they were assigned a residual identification code of “treatingsolution” and were generated from a sulfur complex or H S removal process. These correspond2

to residual codes of “04-B” or “04-C” in Section VII.A and process code “15-B” and “15-E” inSection IV-1.C of the questionnaire.

Table 3.10.7 provides a description of the 1992 management practices, quantitygenerated, number of streams reported, number of streams not reporting volumes (data requestedwas unavailable and facilities were not required to generate it), total and average volumes.


Spent Amine

EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.6. The Agencygathered information suggesting other management practices have been used in other yearsincluding: “onsite Subtitle D landfill” (200 MT) and “offsite incineration” (120 MT). Thesenon-1992 practices are generally comparable to practices reported in 1992 (i.e., off-site SubtitleD landfilling and on-site boiler, respectively).


Properties# of

Values

# ofUnreported


pH 36 67 4.5 9.1 11.8

Reactive CN, ppm 5 98 0 5 12

Reactive S, ppm 10 93 1.41 280 7,500

Flash Point, C 16 87 -10 90.6 168.9

Oil and Grease, vol% 11 92 0 0.1 1

Total Organic Carbon, vol% 16 87 0 10 15

Vapor Pressure, mm Hg 12 91 1 30 300

Vapor Pressure Temperature, C 13 90 15 25 50

Viscosity, lb/ft-sec 10 93 0 0 10

Specific Gravity 34 69 1 1.1 1.1

Specific Gravity Temperature, C 16 87 15 17.5 38

Aqueous Liquid, % 61 42 0 100 100

Organic Liquid, % 43 60 0 0 100

Solid, % 36 67 0 0 20



Table 3.10.8. Spent Amine: Physical Properties

Spent Stretford Solution

EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.7. Even thoughspent Stretford solution has different properties, it is possible that the solution could be managedas the spent amine in Table 3.10.6.



• Tables 3.10.8 and 3.10.9 summarize the physical properties of spent amine and spentStretford solution as reported in Section VII.A of the §3007 survey.

• Four record samples of spent amine solution were collected and analyzed by EPA. The sample locations are summarized in Table 3.10.10.

• No samples of spent Stretford solution were available from the randomly selectedfacilities during record sampling.


Properties# of

Values

# ofUnreported


pH 10 12 8.3 8.8 9.7

Reactive CN, ppm 2 19 1 1.35 1.7

Reactive S, ppm 2 19 0.1 3,190 6,380

Oil and Grease, vol% 1 20 1 1 1


Vapor Pressure, mm Hg 3 18 1.5 10 20

Specific Gravity 8 14 1 1.1 1.5

COD, mg/L 4 17 100 6,930 6,930

Aqueous Liquid, % 9 13 0 90 100


Solid, % 10 12 0.5 10 100



Table 3.10.9. Spent Stretford Solution: Physical Properties

Sample Number Facility Description

R11-SA-01 ARCO, Ferndale, WA Refinery DEA system: circulating amine

R13-SA-01 Shell, Deer Park, TX Refinery DEA system: circulating amine

R14-SA-01 BP, Toledo, OH Refinery DEA system: from sumpcollecting knock-out pot liquid, etc, prior toits exiting the system

R15-SA-01 Total, Ardmore, OK Refinery MDEA system: circulating amine

Table 3.10.10. Off-Specification Treating Solution Record Sampling Locations

All of the samples were taken from refinery amine systems and are believed to representthe various types of spent amine generated by refineries. No samples from the tail gas systemunits were collected. Tail gas residuals are expected to be cleaner because the feeds are cleaner. Therefore, the tail gas treating residuals are expected to exhibit levels of contaminants no higherthan those found in the sampled residuals. No samples of Stretford solution were taken. Stretford systems were not used by the facilities randomly selected by the Agency for recordsampling. Samples of Stretford solution are expected to exhibit higher levels of vanadium thanamine solution because vanadium is present in new Stretford solution; levels of some organiccontaminants may be lower because most refineries use their Stretford system to treat low-organic Claus unit tail gas.

Several of the samples were taken from the process line (i.e., at the time of sampling, therefinery had no immediate plans to remove the sampled treating solution from the system).


However, these refineries indicated they do remove all or part of their circulating amine on aninfrequent basis due to process upset or excessive contaminant levels. The sampled amine isexpected to have contaminant concentrations at least as high as when the circulating amine isremoved from the system. Physical properties such as pH and flash point are expected to besimilar as well.

All four samples were analyzed for total and TCLP levels of volatiles, semivolatiles, andmetals, pH, total amines, and ignitability. Two samples were also analyzed for reactive sulfides. One sample exhibited the characteristic of ignitability. A summary of the results is presented inTable 3.10.11. Only constituents detected in at least one sample are shown in this table.


Source reduction of amine involves modifying the process. During the site visits,information was gathered that several facilities capture the amine for recycling. Two facilitiesreplaced the cloth filter at the sulfur recovery unit with an etched metal mechanical filter. Thenew filter requires less maintenance, and also eliminates amine discharges to the wastewatertreatment plant due to filter change-outs. Another two facilities have installed sumps at thesulfur complex. The sumps capture amine that is drained from the filters during bag change-outsand recycle it to the amine system. Without the sumps, the amine drained from the filters isdischarged to the wastewater treatment plant.

Reference Waste Minimization/Management Methods

Stewart, E.J. and Lanning, R.A. “Reduce Amine Plant Process modification.Solvent Losses, Part 2.” Hydrocarbon Processing. June,1994.

”Liquid Catalyst Efficiently Removes H S From Liquid Lower catalyst quantities needed to remove H S in the2

Sulfur.” Oil & Gas Journal. July 17, 1989. sulfur degassing process.2

Stewart, E.J. and Lanning, R.A. “Reduce Amine Plant Process modification.Solvent Losses, Part 1.” Hydrocarbon Processing. May,1994.

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Table 3.10.11. Characterization Data for Off-Specification Treating Solution from Sulfur Complex and H S Removal2

Volatile Organics - Method 8260A µg/L

CAS No. R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments

Acetone 67641 < 25 < 50 < 25 10 10 10 1

Benzene 71432 < 25 < 50 88 < 5 42 88

Toluene 108883 < 25 < 50 220 < 5 75 220

o-Xylene 95476 < 25 < 50 J 24 < 5 15 24 1

m,p-Xylenes 108383 / 106423 < 25 < 50 69 < 5 37 69

Naphthalene 91203 < 25 < 50 J 32 < 5 19 32 1

Semivolatile Organics - Method 8270B µg/L


Acenaphthene 83329 < 50 < 545 180 < 575 115 180 1

Anthracene 120127 J 18 < 545 250 < 575 134 250 1

Aniline 62553 < 50 J 540 < 50 < 575 213 540 1

Benz(a)anthracene 56553 < 50 < 545 J 34 < 575 34 34 1

Bis(2-ethylhexyl)phthalate 117817 JB 26 < 545 J 17 < 575 22 26 1

Carbazole 86748 J 80 < 1,090 < 100 < 1,150 80 80 1

Chrysene 218019 < 50 < 545 J 71 < 575 61 71 1

Dibenzofuran 132649 < 50 < 545 160 < 575 105 160 1

2,4-Dimethylphenol 105679 110 < 545 J 86 < 575 98 110 1

Fluoranthene 206440 J 17 < 545 < 50 < 575 17 17 1

Fluorene 86737 < 50 < 545 1,100 < 575 568 1,100

2-Methylchrysene 3351324 < 100 < 1,090 J 84 < 1,150 84 84 1

1-Methylnaphthalene 90120 < 100 < 1,090 2,500 < 1,150 1,210 2,500

2-Methylnaphthalene 91576 < 50 < 545 3,400 < 575 1,143 3,400

2-Methylphenol 95487 360 < 545 210 < 575 285 360 1

3/4-Methylphenol NA 1,200 < 545 1,000 < 575 830 1,200

Phenanthrene J 50 < 545 3,000 < 575 1,043 3,000

Phenol 108952 4,400 < 545 3,100 < 575 2,155 4,400

Pyrene J 25 < 545 430 < 575 228 430 1

1-Naphthylamine 134327 < 50 < 545 < 50 J 230 110 230 1

Naphthalene 91203 < 50 < 545 150 < 575 100 150 1

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Table 3.10.11. Characterization Data for Off-Specification Treating Solution from Sulfur Complex and H S Removal2

(continued)

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/L


Aluminum 7429905 0.39 < 0.10 < 0.10 < 0.10 0.17 0.39

Antimony 7440360 0.81 < 0.03 < 0.03 0.62 0.37 0.81

Cadmium 7440439 0.035 < 0.003 < 0.003 0.025 0.016 0.035

Chromium 7440473 0.26 0.99 0.021 0.031 0.326 0.990

Cobalt 7440484 0.11 < 0.025 < 0.025 0.099 0.065 0.110

Copper 7440508 < 0.013 < 0.013 0.034 < 0.013 0.018 0.034

Iron 7439896 39.0 14.0 1.10 0.11 13.6 39.0

Manganese 7439965 0.31 2.30 0.043 < 0.008 0.67 2.30

Potassium 7440097 21.0 < 2.50 < 2.50 22.0 12.0 22.0

Selenium 7782492 0.031 0.61 0.038 0.99 0.42 0.99

Sodium 7440235 8.40 < 2.50 < 2.50 2,300 578 2,300

Zinc 7440666 < 0.01 < 0.01 0.039 < 0.01 0.017 0.039


R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments

Ignitability (oF) > 211 NA > 210 90 NA NA

Corrosivity (pH units) 10 10 8.9 11.5 NA NA

Reactivity - Total ReleasableH2S (mg/L) < 20 NA 48 NA NA NA

Amines - Methyldiethanolamine (mg/L) ND ND ND 36,000 36,000 36,000

Amines - Ethanolamine (mg/L) 4,400 4,500 ND ND 4,450 4,500

Amines - Diethanolamine (mg/L) 330,000 280,000 41,300 ND 217,100 330,000

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.TCLP was not performed because these were liquid samples

Notes:


zero.ND Not Detected.NA Not Applicable.


3.11 CLAY FILTERING

Clay belongs to a broad class of materials designed to remove impurities via adsorption. Examples of clay include Fullers earth, natural clay, and acid treated clay. However, similarmaterials such as bauxite are also available and used to impart similar qualities to the product. In addition, materials such as sand, salt, molecular sieve, and activated carbon are used forremoving impurities by adsorption or other physical mechanisms. All solid materials discussedin Section 3.11.1 are termed as “solid sorbents” for the purposes of defining this residualcategory.

3.11.1 Process Description

Clay or other adsorbents are used to remove impurities from many hydrocarbon streams. Some of these applications are associated with isomerization, extraction, alkylation, and lube oilprocessing; such processes are discussed in the respective sections of this document. Other solidmedia remove impurities from amine solutions used in hydrogen sulfide removal systems; suchmedia were discussed in the Listing Background Document. Solid media used in all otherrefinery processes are summarized and discussed in this section. The principal applications aredescribed below.

Kerosene Clay Filtering: Clay treatment removes diolefins, asphaltic materials, resins,and acids; this improves the color of the product and removes gum-forming impurities (Speight,1991). The RCRA §3007 Survey indicates that approximately 90 facilities use this process;some facilities have multiple treaters or treat different streams, so that an estimated 150processes exist. Most clay treatment is conducted as a fixed bed. A typical clay volume is 2,000ft , distributed in 1 or more vessels. Alternatively to the fixed bed process, the clay can be3

mixed with the hydrocarbon and filtered in a belt press. In addition to kerosene, some facilitiesidentify filtering furnace oils through clay and generating spent clay in a similar manner.

Catalyst Support in Merox and Minalk Systems: The Merox and Minalk caustictreatment systems convert mercaptans to disulfides using oxygen and an organometallic catalystin an alkaline environment. Depending on the process configuration, the disulfides can remainin the hydrocarbon product (a “sweetening” process) or the disulfides can be removed by settling(an “extractive” process). These treatment processes are commonly applied to gasoline, butrefinery streams ranging from propane to diesel undergo this treatment.

The catalyst can either be dissolved in the caustic or can be supported on a fixed bed. Either activated carbon, coal, or charcoal are typically used as support material for solidsupported catalyst (the hydrocarbon passes over the catalyst, where reaction occurs). Thesematerials provide contact area for reaction when the catalyst is dissolved in the caustic. TheRCRA §3007 survey indicates that approximately 25 facilities (using 40 processes) reportedgenerating spent carbon, coal, or charcoal from these processes; additional facilities likelygenerate this residual but did not report generation in the questionnaire because the residual istypically generated infrequently.

Drying: Water is removed from many hydrocarbon streams ranging from diesel fuel topropane. Water must be removed for reasons including: (1) product specifications (e.g., jet fuel


has low tolerances for water content), and (2) reactor feed preparation (e.g., precious metalcatalysts are often poisoned by water). Salt and sand are commonly used for the firstapplication, while molecular sieve is commonly used for the second application.

When hydrocarbon is passed through a fixed bed of sand, the moisture collects on thesand particles and eventually settles to the bottom of the vessel, where the water is removed. Ina salt drier, water in the stream dissolves salt (e.g., sodium chloride) which then collects in thevessel bottom and is periodically removed. As a result, the vessel requires periodic topping withsolid salt.

Salt and sand treaters can be found throughout the refinery to treat hydrocarbons rangingfrom diesel to propane. They are commonly found following aqueous treatments such as causticwashing, water washing, or Merox caustic treatment. In these treatments, the hydrocarbon iscontacted with the aqueous stream; the hydrocarbon then passes through salt or sand to removeresidual moisture. The RCRA §3007 questionnaire indicates that approximately 60 facilities(using 150 processes) reported generating spent salt or sand from these processes; additionalfacilities likely generate this residual but did not report generation in the questionnaire because itwas not generated in 1992.

Molecular sieves are most commonly used to selectively adsorb water and sulfurcompounds from light hydrocarbon fractions such as propane and propylene. The hydrocarbonpasses through a fixed bed of molecular sieve. After the bed is saturated, water is desorbed bypassing heated fuel gas over the bed to release the adsorbed water and sulfur compounds into theregeneration gas stream, which is commonly sent to a flare stack. Molecular sieves are oftenused for drying feed to the isomerization unit and HF acid alkylation unit, applications that arediscussed in Sections 3.4 and 3.5, respectively, of this document. Other applications includedrying propane or propylene prior to entering the Dimersol unit, drying naphtha entering thereformer, and feed preparation for other reaction units. Molecular sieves are also used to drylight-end product streams from the hydrocracker, catalytic reformer, and light-ends recoveryunit. Less common uses also exist for molecular sieves including the separation of light-endfractions such as methanol, butane, and butylene. In total, the RCRA §3007 questionnaireindicates that approximately 70 facilities (using 150 processes) reported generating spentmolecular sieve; this includes the applications of HF acid alkylation and isomerization that arediscussed elsewhere in this document, but excludes additional facilities that are likely generatethis residual but did not report 1992 generation in the questionnaire.

Sulfur and Chloride Guards in Catalytic Reforming: As discussed in the ListingBackground Document, catalytic reforming units require a platinum catalyst; this catalyst isreadily poisoned by sulfur compounds. To prolong catalyst life, many refineries install sulfurtraps to remove sulfur compounds prior to the reforming catalyst bed. This material can consistof granular or pelletized metal oxides, such as copper or magnesium. These materials (1)remove H S, (2) convert mercaptans to H S and organic sulfides, and (3) remove generated H S. 2 2 2

The material can be desorbed, reactivated, and reused (Perry's, 1950). Alumina also is used totreat light naphtha prior to isomerization (which also uses precious metal catalyst). The RCRA§3007 questionnaire indicates that approximately 20 facilities reported generating spent sulfurguards from 35 applications, most often as guards for reforming and isomerization reactors.


Additional facilities may employ sulfur guards but did not report generation in the questionnairebecause the residual is typically generated infrequently.

Alumina beds may be used to remove chlorides from the hydrogen produced from thereforming process. The hydrogen is then used throughout the refinery. The alumina bed isexpected to last for 24-30 months prior to chloride breakthrough, when replacement of thealumina is required. Reformate from the reformer may also be passed through alumina toremove chloride. The RCRA §3007 questionnaire indicates that approximately 15 facilitiesreported generating spent chloride guards from 25 applications, most often in the reformingprocess.

Propane Treating by Alumina: An activated alumina bed is used to de-fluorinatepropane generated from a propane stripper. The propane then is dried in a sand tower and adrier which also contains alumina. Both the defluorinator and drier periodically generate spentalumina.

Particulate Filters: Entrained solids can be removed by in-line cartridge filters. Thesecartridges are commonly used for finishing kerosene, diesel fuel, etc., prior to sale. Approximately 10 facilities reported generating spent cartridges from 20 applications, accordingto the questionnaire results.

In most of the applications discussed above, the use of solid media such as clay, sand,etc. are not the only options refineries have in imparting the desired properties on a product. Forexample, drying can be conducted by simple distillation. Hydrotreating and caustic treating arecommon alternatives to the clay treatment of jet fuel by removing undesirable contaminantsfrom the kerosene/jet fuel fraction. And, as discussed above, the Merox process can beconducted with or without solid supported catalyst.

3.11.2 Treating Clay from Clay Filtering


Generated at many places in the refinery, spent solid sorbents have liquid contentsranging from very low (e.g., for molecular sieves treating light hydrocarbons) to oil-saturatedmaterial (e.g., for clay used for treating kerosene). The substrate is either inorganic (such asalumina, zeolite, or clay) or organic (such as activated carbon). Most applications are fixed bed,where the material is charged to vessels and the hydrocarbon passed through the fixed bed ofsolid sorption media. The fixed bed can remain in service for a period of time ranging fromseveral months to 10 years, depending on the application. At the end of service, the vessel isopened, the “spent” material removed, and the vessel recharged.


streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle Clandfill, transfer as a fuel, etc.).



The spent clay is vacuumed or gravity dumped from the vessels into piles or intocontainers such as drums and roll-off bins. The RCRA §3007 questionnaire and site visitsindicate that very few other interim storage methods are used.

In 1992, approximately 30 facilities reported that 1,700 MT of this residual was managedas hazardous. The most commonly designated waste codes were D001 (ignitable), D008 (TClead), and D018 (TC benzene). This is consistent with how the residual was reported to be5

managed in other years.

One hundred facilities reported generating a total quantity of approximately 9,000 MT ofthis residual in 1992, according to the 1992 RCRA §3007 Questionnaire. There was no reasonto expect that 1992 would not be a typical year with regard to this residual's generation andmanagement. Residuals were assigned to be “treating clay from clay filtering” if they wereassigned a residual identification code of “spent sorbent” (residual coded “07”) and were notgenerated from a process identified as an alkylation, isomerization, extraction, sulfur removal, orlube oil unit (process codes “09,” “10,” “12,” “15,” and “17,” respectively) (sorbents from theseunits are discussed elsewhere in this document or in the Listing Background Document). Thefrequency of generation is highly variable as discussed in Section 3.11.1. Table 3.11.1 providesa description of the 1992 management practices, quantity generated, number of streams reported,number of streams not reporting volumes (data requested was unavailable and facilities were notrequired to generate it), total and average volumes.

The wide array of management methods reflect the numerous applications of sorbents. For example, disposed salt from salt driers can be managed in onsite wastewater treatmentplants, cement plants can accept spent alumina, and catalyst reclaimers can accept sulfur sorbershaving recoverable metals. The large quantity disposed, however, demonstrates that for mostapplications and refineries the spent clay is seen as a low value solid waste.


EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.11.1. The Agencygathered information suggesting other management practices have been used in other yearsincluding: “other recycling, reclamation, or reuse: unknown” (1 MT), “other recycling,reclamation, or reuse: onsite road material” (13.5 MT) and “reuse as a replacement catalyst foranother unit” (5 MT). These non-1992 very small management practices are comparable to therecycling practices reported in 1992.



Streams# of Streams w/

Unreported VolumeTotal

Volume (MT)Average

Volume (MT)


14 3 514 36.7

Disposal in offsite Subtitle D landfill 91 0 3,642.1 40

Disposal in offsite Subtitle C landfill 42 0 1,735 41.3


Disposal in onsite Subtitle D landfill 15 0 1,031.9 68.8

Evaporation 1 0 7.9 7.9

Offsite incineration 7 0 42.1 6

Offsite land treatment 9 0 198.3 22


Other disposal onsite: bioremediation, fill material, or onsiteberms

5 0 57.4 11.5

Other recovery onsite: recycle toprocess

1 0 20.1 20.1

Other recycling, reclamation, orreuse: cement plant

5 0 161.4 32.3

Offsite filter recycling 2 0 38 19

Storage in pile 2 0 128 64

Recovery in coker 1 0 20 20

Transfer for direct use as a fuel or tomake a fuel

1 0 95 95


6 0 175.8 29.3

Transfer metal catalyst forreclamation or regeneration

10 0 89.4 8.9

Transfer to other offsite entity/carbonregeneration

2 0 53.6 26.8


1 0 4.5 4.5

TOTAL 232 4 8,990 38.8

Table 3.11.1. Generation Statistics for Treating Clay from Clay Filtering, 1992



• Table 3.11.2 summarizes the physical properties of the spent clay as reported inSection VII.A of the §3007 survey.

• Four record samples of spent clay were collected and analyzed by EPA. These spentclays represent some of the various types of applications used by the industry. Sampling information is summarized in Table 3.11.3.


Properties# of

Values

# ofUnreported


pH 171 334 4.6 7.6 10.4

Reactive CN, ppm 100 405 0 0.5 50

Reactive S, ppm 106 399 0 10 125

Flash Point, C 132 373 57.2 93.3 200

Oil and Grease, vol% 94 411 0 1 17.5



Specific Gravity Temperature, C 50 455 15 20 25

BTU Content, BTU/lb 31 474 0 2,000 13,500

Aqueous Liquid, % 230 275 0 0 10.3


Solid, % 346 159 89.0 100 100

Particle >60 mm, % 59 446 0 0 100

Particle 1-60 mm, % 91 414 0 100 100

Particle 100 µm-1 mm, % 70 435 0 10 100

Particle 10-100 µm, % 54 451 0 0 20

Particle <10 µm, % 49 456 0 0 0

Median Particle Diameter, microns 48 457 0 1,000 3,000



Table 3.11.2. Treating Clay from Clay Filtering: Physical Properties

Sample # Facility Description

R1-CF-01 Marathon Indianapolis, IN kerosene/jet treating clay (fixed bed process)

R6-CF-01 Shell Norco, LA kerosene/jet treating clay (bag filter process,generated daily)

R11-CF-01 ARCO Ferndale, WA reformer unit sulfur trap

R23-CF-01 Chevron, Salt Lake City, UT kerosene/jet treating clay

Table 3.11.3. Treating Clay Record Sampling Locations


The collected samples are expected to be representative of treating clay from kerosenetreatment. Section 3.11.1 shows that kerosene clay treatment represents the highest single use ofsorbents in refineries (outside of the sulfur recovery, isomerization, and alkylation processes thatare not included in the scope of this study residual). In addition, a cursory review of the 1992generation data presented in Section 3.11.2.2 shows that the 1992 generation rate of spentkerosene treating clay represents at least half of the total 1992 quantity from all sourcesidentified in Section 3.11.1.

One of the samples is representative of a sulfur guard bed. Other applications of spentsorbents (discussed in Section 3.11.1) are not well represented by the record sampling. Specifically:

• Spent activated carbon from Merox treatment, salt and sand from product drying,particulate filters, and chloride removal beds are not expected to resemble thesematerials.

• Spent molecular sieves and alumina are not represented by the collected recordsamples. However, they may be represented by the record samples of isomerizationtreating clay and alkylation treating clay, discussed in Sections 3.4 and 3.5,respectively.

All four record samples were analyzed for total and TCLP levels of volatiles,semivolatiles, and metals. Two samples were analyzed for ignitability and all were analyzed forreactivity (pyrophoricity). One of the samples was found to exhibit the ignitabilitycharacteristic. High manganese concentrations in one sample result from the adsorbent make-up. A summary of the results is presented in Table 3.11.4. Only constituents detected in at leastone sample are shown in this table.


One facility reported that its jet fuel treating clay is regenerated once by back-washingthe clay bed with jet fuel to “fluff” the clay and alleviate the pressure drop.

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Table 3.11.4. Residual Characterization Data for Treating Clay


CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments

Acetone 67641 260,000 < 565 < 25 < 1,250 65,460 260,000

Benzene 71432 < 125,000 8,500 540 < 1,250 3,430 8,500 1

n-Butylbenzene 104518 < 125,000 94,000 < 25 < 1,250 31,758 94,000 1

sec-Butylbenzene 135988 < 125,000 54,000 < 25 < 1,250 18,425 54,000 1

Ethylbenzene 100414 < 125,000 76,000 J 28 2,800 26,276 76,000 1

Isopropylbenzene 98828 < 125,000 44,000 < 25 < 1,250 15,092 44,000 1

p-Isopropyltoluene 99876 < 125,000 59,000 < 25 < 1,250 20,092 59,000 1

n-Propylbenzene 103651 < 125,000 70,000 < 25 < 1,250 23,758 70,000 1

Methylene chloride 75092 < 125,000 < 565 100 < 1,250 100 100 1

Toluene 108883 < 125,000 140,000 340 3,600 67,235 140,000

1,2,4-Trimethylbenzene 95636 580,000 620,000 < 25 32,000 308,006 620,000

1,3,5-Trimethylbenzene 108678 < 125,000 210,000 < 25 13,000 87,006 210,000

o-Xylene 95476 < 125,000 180,000 89 7,200 78,072 180,000

m,p-Xylenes 108383 / 106423 300,000 380,000 130 23,000 175,783 380,000

Naphthalene 91203 310,000 350,000 < 25 9,800 167,456 350,000



Acetone 67641 43,000 < 50 < 50 B 100 10,800 43,000

Benzene 71432 < 1,250 100 J 44 < 50 65 100 1

Ethylbenzene 100414 < 1,250 190 < 50 < 50 97 190 1

Methylene chloride 75092 2,600 < 50 1,700 < 50 1,100 2,600

Toluene 108883 < 1,250 850 210 < 50 370 850 1

1,2,4-Trimethylbenzene 95636 4,900 840 < 50 J 62 1,463 4,900

1,3,5-Trimethylbenzene 108678 < 1,250 270 < 50 < 50 123 270 1

o-Xylene 95476 < 1,250 610 < 50 J 44 235 610 1

m,p-Xylene 108383 / 106423 < 1,250 1,200 < 50 110 453 1,200 1

Naphthalene 91203 < 1,250 650 < 50 J 71 257 650 1



Bis(2-ethylhexyl) phthalate 117817 < 6,600 < 4,125 J 100 < 4,150 100 100 1

Carbazole 86748 < 13,200 < 8,250 < 330 J 6,000 3,165 6,000 1

Di-n-butyl phthalate 57976 < 6,600 < 4,125 420 < 4,150 420 420 1

Dibenzofuran 132649 < 6,600 J 24,000 < 165 < 4,150 8,729 24,000

Fluorene 86737 < 6,600 < 4,125 < 165 20,000 7,723 20,000

2,4-Dimethylphenol 105679 < 6,600 < 4,125 2,500 < 4,150 2,500 2,500 1

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Table 3.11.4. Residual Characterization Data for Treating Clay (continued)

Semivolatile Organics - Method 8270B µg/kg (continued)


2-Methylphenol 95487 < 6,600 < 4,125 9,000 < 4,150 5,969 9,000

3/4-Methylphenol NA < 6,600 < 4,125 30,000 < 4,150 11,219 30,000

1-Methylnaphthalene 90120 980,000 890,000 < 165 78,000 487,041 980,000

2-Methylnaphthalene 91576 150,000 1,200,000 < 165 92,000 360,541 1,200,000

Naphthalene 91203 120,000 740,000 < 165 43,000 225,791 740,000

Phenanthrene 85018 < 6,600 J 4,800 < 165 25,000 9,141 25,000

Phenol 108952 < 6,600 < 4,125 20,000 < 4,150 8,719 20,000



Bis(2-ethylhexyl) phthalate 117817 290 J 16 < 250 < 50 152 290

Dibenzofuran 132649 < 50 J 17 < 250 < 50 17 17 1

Di-n-butyl phthalate 84742 < 50 JB 19 < 250 < 50 19 19 1

2,4-Dimethylphenol 105679 350 J 73 1,400 < 50 468 1,400

Fluorene 86737 < 50 J 41 < 250 < 50 41 41 1

1-Methylnaphthalene 90120 J 190 550 < 250 J 130 280 550

2-Methylnaphthalene 91576 220 780 < 500 120 405 780

Naphthalene 91203 600 700 < 250 140 423 700

2-Methylphenol 95487 310 < 50 7,800 < 50 2,053 7,800

3/4-Methylphenol (total) NA 580 < 50 6,300 < 50 1,745 6,300

Phenol 108952 < 50 < 50 2,300 < 50 613 2,300



Aluminum 7429905 12,000 6,800 110,000 13,000 35,450 110,000

Arsenic 7440382 3.20 < 1.00 14.0 16.0 8.55 16.0

Barium 7440393 78.0 < 20.0 < 20.0 59.0 44.3 78.0

Beryllium 7440417 3.80 < 0.50 < 0.50 2.50 1.83 3.80

Calcium 7440702 4,500 16,000 < 500 4,400 6,350 16,000

Chromium 7440473 37.0 24.0 34.0 39.0 33.5 39.0

Cobalt 7440484 12.0 < 5.00 34.0 11.0 15.5 34.0

Copper 7440508 < 2.50 < 2.50 5.30 620 158 620

Iron 7439896 9,400 3,800 97.0 9,800 5,774 9,800

Lead 7439921 4.80 1.90 2.70 6.00 3.85 6.00

Magnesium 7439954 9,400 10,000 < 500 9,300 7,300 10,000

Manganese 7439965 130 140 150,000 120 37,598 150,000

Mercury 7439976 < 0.05 < 0.05 < 0.05 0.26 0.10 0.26

Petroleum

Refining Industry S

tudy156

August 1996

Table 3.11.4. Residual Characterization Data for Treating Clay (continued)

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (continued)


Molybdenum 7439987 < 6.50 < 6.50 14.0 < 6.50 8.38 14.0

Nickel 7440020 16.0 < 4.00 < 4.00 31.0 13.8 31.0

Potassium 7440097 1,400 < 500 < 500 1,300 925 1,400

Selenium 7782492 < 0.50 < 0.50 22.0 < 0.50 5.88 22.0

Silver 7440224 < 1.00 < 1.00 70.0 < 1.00 18.3 70.0

Sodium 7440235 34,000 < 500 < 500 < 500 8,875 34,000

Vanadium 7440622 37.0 21.0 34.0 35.0 31.8 37.0

Zinc 7440666 47.0 19.0 < 2.00 55.0 30.8 55.0



Aluminum 7429905 < 1.00 < 1.00 < 1.00 3.90 1.73 3.90

Arsenic 7440382 < 0.05 < 0.05 < 0.05 0.13 0.07 0.13

Calcium 7440702 54 590 < 25.0 60.0 182 590

Copper 7440508 < 0.13 < 0.13 < 0.13 0.89 0.32 0.89

Iron 7439896 < 0.50 < 0.50 < 0.50 1.00 0.63 1.00

Magnesium 7439954 < 25.0 91 < 25.0 < 25.0 41.5 91.0

Manganese 7439965 < 0.08 2.60 1,400 0.85 351 1,400

Silver 7440224 < 0.05 < 0.05 0.10 < 0.05 0.06 0.10

Zinc 7440666 < 0.10 B 0.76 < 0.10 B 0.27 0.31 0.76


R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments

Ignitability ( oF ) 185 131 NA NA NA NA

Comments:


Notes:


zero.ND Not Detected.NA Not Applicable.


3.12 RESIDUAL OIL TANK STORAGE

Almost every refinery stores its feed and products in tanks onsite. Occasionally (every10 to 20 years), tanks require sediment removal due to maintenance, inspection, or sedimentbuildup. These tank bottoms are removed by techniques ranging from manual shoveling torobotics and filtration. Residual oil tank sludge is a study residual of concern.

Residual oil is generally considered to be equivalent to No. 6 fuel oil which is a heavyresidue oil sometimes called Bunker C when used to fuel ocean-going vessels. Preheating isrequired for both handling and burning. It is typically produced from units such as atmosphericand vacuum distillation, hydrocracking, delayed coking, and visbreaking. The fluid catalyticcracking unit also contributes to the refinery's heavy oil pool, but EPA terms this material“clarified slurry oil,” or CSO, and discussed this product separately in the Listing BackgroundDocument (October 31, 1995).

According to DOE's Petroleum Supply Annual, approximately 400 million barrels of“residual oil” was domestically used in 1992 (including imports and exports). The use profile in1994 was as follows (DOE's Fuel Oil and Kerosene Sales 1994):

Sector 1990 Consumption of Residual Fuel OilElectric Utility 40%Shipping 35%Industrial 15%Commercial and Other 10%

The larger utilities often have their own specifications when purchasing residual fuel oil. Thesecan include sulfur, nitrogen, ash, and vanadium. The current ASTM standard for No. 6 oil (D-396) specifies only three parameters: minimum flash point (of 150 F), maximum water andsediment (of 2 percent), and a viscosity range (Bonnet, 1994). Thus, the characteristics ofresidual oil, and the generated tank sludge, can vary greatly depending on the buyer and therefinery.

3.12.1 Residual Oil Storage Tank Sludge

In 1992, 125 U.S. refineries reported approximately 717 residual oil storage tanks. Fromthe survey, tank volume was reported for about 10 percent (73) of these tanks (excludingoutliers); the average tank volume was approximately 77,000 barrels. DOE's Petroleum SupplyAnnual 1992 reported that refineries produced about 327 million barrels of No. 6 fuel oil orresidual oil or approximately 900,000 barrels per day (this likely includes CSO).


Residual oil tank sludge consists of heavy hydrocarbons, rust and scale from processpipes and reactors, and entrapped oil that settles to the bottom of the tank. It can be manually re-moved directly from the tank after drainage of the residual oil or, commonly, removed using avariety of oil recovery techniques. The recovered oil is returned generally to slop oil storagewhile the remaining solids are collected and discarded as waste.


streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle Clandfill, recovery onsite in coker, etc.).


Once a tank is taken out of service, many refineries use in situ and ex situ oil recoverytechniques. Common in situ oil recovery techniques include hot distillate washing, and steamstripping. This allows entrapped oil to float to the top of the sediment layer and be recoveredprior to removal of the sediment from the tank. Ex situ recovery methods are usually performedby a contractor at the tank site and include filtration, centrifuging, and settling. Separated oil isrecycled back to the process or sent to the slop oil tanks, and the water phase is sent to thewastewater treatment plant (WWTP). The solids are managed in a variety of ways, butprimarily are disposed of in Subtitle C and D landfills (78 percent in 1992).

Many refineries reduce tank bottom buildup with in-tank mixers. Mixers keep thesediments or solids continuously in suspension so that they travel with the residual oil.

In 1992, less than one percent of the volume of residual oil tank bottom sludge wasreported to be managed as hazardous. Of the few refineries that reported a hazardous waste6

designation for this residual in 1992, only one reported a hazardous waste code (the othersspecified handling the sludge as hazardous without designating a code).


The refineries reported generating 9,107 MT of residual oil tank bottom sludge in 1992. Residual oil tank sludge includes sludges from No. 6 oil and similar product tanks. Sludgesfrom tanks identified as containing a mixture of residual oil and clarified slurry oil wereincluded in the scope of K170 and are omitted here. Residuals were assigned to be “residual oiltank sludge” if they were assigned a residual identification code of “residual oil tank sediment,”corresponding to residual code “01-B” in Section VII.1 of the questionnaire. Processwastewaters, decantates, and recovered oils (e.g., from deoiling or dewatering operations) wereeliminated from the analysis. These correspond to residual codes “09,” “10,” and “13” (newlyadded “recovered oil”) in the questionnaire. Quality assurance was conducted by ensuring thatall residual oil tank sludges previously identified in the questionnaire (i.e., in Section V.D) wereassigned in Section VII.1. Table 3.12.1 provides a description of the 1992 managementpractices, quantity generated, number of streams reported, number of streams not reportingvolumes, and average volumes.

When cleaning a tank, it is common for refineries to use some type of in situ treatment,such as washing with lighter fuel, to recover oil from the top layers of sludge where there is ahigh percentage of free oil. However, treatment or recovery practices after this depend on therefinery's planned final management method. If land disposed (as most residual oil tank sludgewas in 1992), low free liquid must be achieved; such levels can be achieved by sludgedeoiling/dewatering or stabilization. A refinery may conduct this



Streams


VolumeTotal Volume

(MT)Average

Volume (MT)


1 0 47 47

Disposal in offsite Subtitle D landfill 13 4 6,458 496.8

Disposal in offsite Subtitle C landfill 8 0 622 77.8

Disposal in onsite Subtitle C landfill 2 0 4 2


Disposal in onsite surface impoundment 1 0 132 132

Offsite land treatment 1 1 4 4


Other recycling, reclamation, or reuse: cover for onsite landfill

1 0 7.2 7.2

Recovery onsite via distillation 1 3 310 310


1 0 35 35

Transfer to another petroleum refinery 1 0 927 927

TOTAL 35 8 9,107 260.2

Table 3.12.1. Generation Statistics for Residual Oil Tank Sludge, 1992

treatment for only some of the waste (e.g., the top layers); in the deeper sections of sludge wherefree liquid levels are lower no treatment may be performed. In addition to lower liquid levels,treatment or deoiling may be used to achieve lower levels of benzene or other hazardousproperties.


EPA believes that most of the plausible management practices for this residual werereported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.12.1. The Agencygathered information suggesting other management practices have been used in other yearsincluding: “recovery onsite in an asphalt production unit” (9.2 MT), “transfer for direct use as afuel or to make a fuel” (380.8 MT), “transfer with coke product or other refinery product” (5MT), “onsite industrial furnace” (39 MT), “recycle to process” (unknown quantity), “recovery incoker” (unknown quantity), and “recovery in a catalytic cracker” (unknown quantity). Thesenon-1992 management practices are generally comparable to the recycling practices reported in1992.




• Table 3.12.2 summarizes the physical properties of residual oil tank sludges asreported in Section VII.A of the §3007 survey.

• Two record samples of actual residual oil sludge were collected and analyzed by EPA. These sludges represent the various types of treatment typically used by the industryand are summarized in Table 3.12.3.

Table 3.12.4 provides a summary of the characterization data collected under thissampling effort. The record samples collected are believed to be representative of residual oiltank sludges generated by the industry.

The samples collected of the composite of oily and de-oiled sediment are representativeof industry treatment practices. As reported in the RCRA 3007 questionnaires, 10 of the 34residual oil tank sludges (30 percent) that were ultimately managed in a land treatment or landfillin 1992 were deoiled in some manner, most often by filtration or centrifuge. This managementresulted in volume reduction averaging 55 percent. Another 7 (20 percent) were stabilized,resulting in the volume increasing by an average of 55 percent. The remaining 17 residuals (50percent) were not reported to be treated ex situ in any manner. The sampled refineries representtwo alternative interim management procedures: free liquid reduction using stabilization(Amoco), and ex situ deoiling (Star). Therefore, the record samples represent the various typesof ex situ treatment typically performed for residual oil tank sludge, but may not represent casesin which no treatment is performed. However, the same contaminants will be present in all threetypes of sludge (i.e., deoiled. stabilized, and untreated), but their levels may differ.

As illustrated in Table 3.12.4, none of the record samples exhibited a hazardous wastecharacteristic. Only constituents detected in at least one sample are shown in this table.


Only a small quantity of sludge was reported to be deoiled in 1992, as reported in the§3007 survey. Of the 34 residuals disposed in landfills or land treatment units in 1992, 10residuals, totaling approximately 1,000 MT. The remaining 24 residuals, totaling approximately7,600 MT, were reported to be untreated or underwent volume addition treatment (such asstabilization. As stated in Section 3.12.1.3, the average volume reduction achieved by deoilingwas 55 percent (as calculated from those facilities providing sludge quantities prior to andfollowing deoiling in 1992).


Properties# of

Values# of Unreported

Values1 10th % Mean 90th %

pH 39 87 5.5 7 8.5

Reactive CN, ppm 27 99 0 0.3 5

Reactive S, ppm 27 99 0 2.5 15

Flash Point, C 42 84 60 93.3 140

Oil and Grease, vol% 36 90 9 34.1 99

Total Organic Carbon, vol% 20 106 3.5 51 85.3

Vapor Pressure, mm Hg 11 115 0 0.1 10

Vapor Pressure Temperature, C 9 117 25 37.8 38

Viscosity, lb/ft-sec 6 120 0.01 50.2 500


BTU Content, BTU/lb 16 110 600 5,000 20,000

Aqueous Liquid, % 78 48 0 0 50


Solid, % 91 35 1 60 100

Other, % 65 61 0 0 0

Particle >60 mm, % 4 122 0 0 0

Particle 1-60 mm, % 6 120 0 50 100

Particle 100 µm-1 mm, % 5 121 0 50 100

Particle 10-100 µm, % 4 122 0 0 1

Particle <10 µm, % 4 122 0 0 0

Median Particle Diameter, microns 3 123 0 0 15,000



Table 3.12.2. Residual Oil Tank Sludge: Physical Properties

Sample No. Facility Description:

R8B-RS-01 Amoco, Texas City, TX Residual oil and CSO mixed. Cleaning1

procedure: pumped down, mixed withdiatomaceous earth, removed with backhoe.

R22-RS-01 Star, Port Arthur, TX Residual oil. Cleaning procedure: washed2

with lighter oil, centrifuged to generate cake.

The refinery has a fluid catalytic cracking unit and generates CSO. An unknown quantity of CSO was stored in the1

sampled tank.

The refinery has a fluid catalytic cracking unit and generates CSO. It is unknown if, or to what extent, CSO was2

stored in the sampled tank.

Table 3.12.3. Residual Oil Tank Sludge Record Sampling Locations


Table 3.12.4. Residual Oil Tank Sludge Characterization


CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments

n-Butylbenzene 104518 < 6,250 3,600 3,600 3,600 1

Ethylbenzene 100414 13,000 J 1,600 7,300 13,000

p-Isopropyltoluene 99876 < 6,250 J 470 470 470 1

n-Propylbenzene 103651 J 6,850 J 1,600 4,225 6,850

Toluene 108883 26,000 < 1,250 13,625 26,000

1,2,4-Trimethylbenzene 95636 43,000 18,000 30,500 43,000

1,3,5-Trimethylbenzene 108678 J 11,000 4,200 7,600 11,000

o-Xylene 95476 19,000 J 1,800 10,400 19,000

m,p-Xylenes 108383 / 106423 51,000 7,400 29,200 51,000

Naphthalene 91203 64,000 19,000 41,500 64,000



Benzene 71432 110 < 50 80 110

Ethylbenzene 100414 J 55 < 50 53 55

Toluene 108883 690 < 50 370 690

1,2,4-Trimethylbenzene 95636 J 79 < 50 65 79

Methylene chloride 75092 B 1,200 < 50 625 1,200

o-Xylene 95476 J 96 < 50 73 96

m,p-Xylene 108383 / 106423 220 JB 28 124 220

Naphthalene 91203 J 91 J 46 69 91


CAS No R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments

Acenaphthene 83329 60,000 27,000 43,500 60,000

Anthracene 120127 150,000 < 4,125 77,063 150,000

Benz(a)anthracene 56553 480,000 9,200 244,600 480,000

Benzofluoranthene (total) NA 130,000 34,000 82,000 130,000

Benzo(g,h,i)perylene 191242 450,000 36,000 243,000 450,000

Benzo(a)pyrene 50328 250,000 87,000 168,500 250,000

Bis(2-ethylhexyl)phthalate 117817 < 10,313 10,000 10,000 10,000 1

Carbazole 86748 < 20,625 J 16,000 16,000 16,000 1

Chrysene 218019 800,000 170,000 485,000 800,000

Dibenzofuran 132649 25,000 8,700 16,850 25,000

Dibenz(a,h)anthracene 53703 65,000 J 8,000 36,500 65,000

3,3'-Dichlorobenzidine 91941 < 10,313 87,000 48,656 87,000

Fluoranthene 206440 120,000 < 4,125 62,063 120,000

Fluorene 86737 160,000 38,000 99,000 160,000

Indeno(1,2,3-cd)pyrene 193395 58,000 < 4,125 31,063 58,000

Phenanthrene 85018 1,000,000 220,000 610,000 1,000,000

Pyrene 129000 3,500,000 46,000 1,773,000 3,500,000

1-Methylnaphthalene 90120 500,000 250,000 375,000 500,000

2-Methylnaphthalene 91576 650,000 410,000 530,000 650,000

2-Methylchrysene 3351324 380,000 < 8,250 194,125 380,000

Naphthalene 91203 230,000 110,000 170,000 230,000

Table 3.12.4. Residual Oil Tank Sludge Characterization (continued)




Di-n-butylphthalate 84742 < 50 JB 24 24 24 1

1-Methylnaphthalene 90120 J 28 J 54 41 54

2-Methylnaphthalene 91576 J 37 J 74 56 74

Naphthalene 91203 J 37 J 73 55 73



Aluminum 7429905 9,100 38,000 23,550 38,000

Arsenic 7440382 3.00 < 1.00 2.00 3.00

Barium 7440393 < 20.0 230 125 230

Beryllium 7440417 1.80 < 0.50 1.15 1.80

Calcium 7440702 < 500 1,400 950 1,400

Chromium 7440473 11.0 31.0 21.0 31.0

Cobalt 7440484 130 < 5.00 67.5 130

Copper 7440508 7.40 110 58.7 110

Iron 7439896 1,600 11,000 6,300 11,000

Lead 7439921 6.50 84.0 45.3 84.0

Magnesium 7439954 < 500 4,300 2,400 4,300

Manganese 7439965 12.0 67.0 39.5 67.0

Mercury 7439976 1.50 < 0.05 0.78 1.50

Molybdenum 7439987 330 18.0 174 330

Nickel 7440020 410 83.0 247 410

Sodium 7440235 < 500 3,200 1,850 3,200

Vanadium 7440622 1,400 480 940 1,400

Zinc 7440666 75.0 200 138 200



Aluminum 7429905 < 1.00 3.70 2.35 3.70

Iron 7439896 < 0.50 10.0 5.25 10.0

Manganese 7439965 < 0.08 1.10 0.59 1.10

Zinc 7440666 B 0.26 1.20 0.73 1.20

Comments:


Notes:

B Analyte also detected in the associated method blank.J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the

result is less than the laboratory detection limit, but greater than zero.ND Not Detected.NA Not Applicable.


In situ oil recovery techniques can greatly reduce the total amount of residual oil tanksludge to be disposed as well as reduce volatile constituents such as benzene. As discussedabove, recovery methods include distillate washing, nonpetroleum solvent washing, water washwith surfactant, and steam stripping. These operations allow entrapped oil to float to the top ofthe sediment layer and be recovered prior to removal from the tank. Separated oil is recycledback to the process or sent to the slop oil tanks, and the water phase is sent to the WWTP.

Oily sludges are emulsions formed due to a surface attraction among oily droplets, waterdroplets, and solid particles. If the solids are large and dense, the resultant material will settleand become a sludge. The surface charge interactions between the solid particles and oildroplets cause the sludge to become stable and difficult to separate. However, the sludge can beseparated into its individual components by mechanically removing the solids or by neutralizingthe surface charge on the solids and oil droplets.

The predominant method of minimizing the formation of tank sludge is the use of mixersto keep the sludges continuously in suspension. A common mixer configuration is a sweepingmixer that automatically oscillates to produce a sweeping motion over the floor of the tank,keeping the heavy oil and particles suspended.

Of the twenty facilities that EPA visited, eight listed methods in recovering oil from tanksludges. Several facilities wash the tanks with light oils and water, whereas another facilitywashes with a surfactant followed by pressure filtration.

Reference Waste Minimization/Management Methods

”Re-refiner Fluidizes Tank Residue Using Portable Mixer.” A portable mixer was used to cut lighter oil into theOil & Gas Journal. September 5, 1994. partially gelled residue.

Kuriakose, A.P., Manjooran, S. Jochu Baby. Utilizing waste sludge.”Utilization of Refinery Sludge for Lighter Oils and IndustrialBitumen.” Energy & Fuels. vol.8, no.3. May-June, 1994.

”Environmental Processes '93: Challenge in the '90s.” A variety of technologies described, such asHydrocarbon Processing. August, 1993. bioslurry treatment of oily wastes, oily-waste

recovery, and evaporation/solvent extraction.

”Waste Minimization in the Petroleum Industry: A Sludge formation can be minimized by mixingCompendium of Practices.” API. November, 1991. contents of tank.


BIBLIOGRAPHY

1992 RCRA §3007 Survey of the Petroleum Refining Industry Database.

Department of Energy, Energy Information Administration. Petroleum Supply Annual 1992,Volume 1. May 1993.

Donald Bonett, “ASTM D-396 Specification for No. 6 Fuel Oil,” in Proceedings, 1993 Fuel OilUtilization Workshop, Electric Power Research Institute, August 1994 (page 3-101).

Fuel Oil and Kerosene Sales 1994, U.S. Department of Energy, September 1995 (DOE/EIA-0340(92)/1).

Hydrocarbon Processing. “Refining Processes '94.” November 1994.

Hydrocarbon Processing. “Gas Processing '94.” April 1994.

Kirk-Othmer. Encyclopedia of Chemical Technology. Third Edition, Volume 22. 1983.

McKetta, John J. Petroleum Processing Handbook. Marcel Dekker, Inc. 1992.

Meyers, Robert A. Handbook of Petroleum Refining Processes. McGraw-Hill Book Company. 1986.

Perry's, 1950. John H. Perry, ed. Chemical Engineer's Handbook. McGraw-Hill, New York. Third edition, 1950.

Speight, 1991. James Speight. The Chemistry and Technology of Petroleum. Marcel Dekker,New York. Second edition, 1991.

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